Smart sustainable combinations in the North Sea Area (NSA)

Transcription

FINAL DRAFT SEPTEMBER 2015
Smart sustainable combinations in
the North Sea Area (NSA)
Make the energy transition work efficiently and effectively
by
Catrinus J. Jepma*, Energy Delta Institute
Further research team
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
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Jean Paul Noujeim and Erwin Hofman, JIN Climate and Sustainability
Miralda van Schot, Energy Delta Institute (EDI)
Paula Schulze and Onno Florission, DNV GL
* Professor of Energy and Sustainability, University of Groningen
This draft or parts thereof may not be cited, copied, reproduced or transmitted in any form, or by any means,
whether digitally or otherwise without the prior written consent of Energy Delta Institute.
Smart sustainable combinations in the North Sea Area (NSA):
Make the energy transition work efficiently and effectively
Acknowledgement
This study has been prepared on behalf of the Netherlands’ Ministry of Economic Affairs and NOGEPA.
The research team thanks them for their input and comments. We also benefited greatly from data
provided by EBN and discussions with various colleagues from the European North Sea Energy Alliance
(ENSEA) project, including dr. Koos Lok of Energy Valley.
Implementing partners
Background reports
The following background reports have been used as an input to this study. They can be requested at
the Energy Delta Institute (EDI), attention Bianca Dijkstra, secretariat ([email protected]).
Van Schot, M. (2015), The value of offshore electric energy storage: A business case related to green
decommissioning, Energy Delta Institute (EDI).
Noujeim, J.P. (2014), Power to Gas Model for Reuse of Offshore O&G Facilities, EUREC.
Noujeim, J.P. (2015), Power-to-Gas on an Offshore Platform: System Analysis and Technical Barriers,
JIN Climate and Sustainability.
Schulze, P. & Florisson, O. (2015), Green Decommissioning: Re-Use of North Sea Offshore Assets for
Power-to-Gas, Energy Delta Institute (EDI).
Smart sustainable combinations in the North Sea Area
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Table of contents
TABLE OF CONTENTS ...................................................................................................... 3
LIST OF FIGURES AND TABLES ......................................................................................... 4
LIST OF ABBREVIATIONS ................................................................................................. 5
1.
INTRODUCTION ................................................................................................ 7
2.
SMART SUSTAINABLE COMBINATIONS: OVERALL PERSPECTIVES ..................... 11
2.1.
Scenarios
14
2.2.
Quantitative potential impact of the scenarios
17
3.
ECONOMIC AND BUSINESS ISSUES .................................................................. 22
3.1.
The power-to-gas end-use options
22
3.2.
Option 1: Hydrogen-to-power
23
3.3.
Option 2: Hydrogen as a feedstock for the chemical industry
23
3.4.
Option 3: Infeed in gas infrastructure
25
3.5.
Options 4/5: Hydrogen for mobility (shipping and automotive sector)
25
3.6.
Option 6: Hydrogen to methane gas
26
3.7.
Valuation of scenarios
26
3.8.
Sensitivity analysis
29
3.9.
The future case
30
4.
TECHNICAL ISSUES.......................................................................................... 31
4.1.
Introduction
31
4.2.
Offshore power-to-gas demonstration plant: some overall considerations
31
4.3.
Barriers
34
5.
POSSIBLE FURTHER STEPS............................................................................... 39
6.
CONCLUSION ................................................................................................. 41
ANNEX 1: CONVERSION MODEL USED FOR THE ENERGY CONVERSION PROCESS ............ 42
ANNEX 2: NPV MODEL USED FOR ECONOMIC ANALYSIS AND RELATED DATA FOR THE
NETHERLANDS’ SITUATION ............................................................................. 44
Methodology
44
Data with respect to the Netherlands’ situation
47
REFERENCES ................................................................................................................. 51
3
List of figures and tables
Figure 1. Netherlands government's vision on offshore wind energy deployment (I&M and EZ, 2014).
Currently, a parliamentary discussion is ongoing on the issue whether future offshore wind farms will
be located closer to the coast (between the 10 and 12 mile zones). ................................................... 13
Figure 2. Graphical illustration of medium-term scenario .................................................................... 16
Figure 3. Graphical illustration of long-term scenario .......................................................................... 17
Figure 4. Electrolyser capacity vs number of households for 510 curtailment hours........................... 18
Figure 5. Electrolyser capacity vs number of households for 1119 curtailment hours......................... 19
Figure 6. Green gas production vs demand with 1119 curtailment hours ........................................... 19
Figure 7. Effect of wind penetration on an 80 MW electrolyser........................................................... 20
Figure 8. Excess generated hydrogen vs electrolyser capacity ............................................................. 21
Figure 9. Electricity outcome for a 200 MW system ............................................................................. 21
Figure 10. Electricity output for a 270 MW system .............................................................................. 21
Figure 11. Hydrogen pipeline networks of ‘Air Liquide’ and ‘Air Products’ (Perrin, et al., 2007). ........ 24
Figure 12. Daily peak and off-peak electricity prices from April 2006 until April 2014 ........................ 48
Figure 13. Historical and simulated electricity prices for the Netherlands ........................................... 48
Figure 14. Day-ahead settlement prices ............................................................................................... 48
Figure 15. Typical 4-pile drilling/production facility complete removal cost in 2012, in the US Gulf of
Mexico (Byrd, et al., 2014, p. 27). ......................................................................................................... 51
Table 1. Overview of main markets for hydrogen and their characteristics ......................................... 22
Table 2. NPV calculations of the five scenarios ..................................................................................... 28
Table 3. NPV calculations of the future scenarios................................................................................. 30
Table 4: Important parameters of the main water electrolysis technologies....................................... 34
Table 5. Available platforms per designated offshore wind energy area on the DCS .......................... 40
Table 6. Parameters and values ............................................................................................................ 46
Table 7. Overview of electrolysers (Meier, 2014) ................................................................................. 49
Table 8. Energy consumption and water costs of commercial large-scale desalination (Ghaffour, et al.,
2012)...................................................................................................................................................... 49
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List of abbreviations
AC
AEC
CAPEX
CE
CCS
CO2
DC
DCS
DVGW
EBIT
EEG
EGR
EOR
EU
EWEA
FCF
GBM
GE
GW
H2O
H2S
HVDC
IRR
kWh
LNG
MC
Mt
MVAC
MW
µV
Nm3
NOPLAT
NPV
NREL
NSA
O&G
OSPAR
PEM
PGM
R&D
ROV
SDE+
SNG
Alternating current
Alkaline electrolytic cell
Capital expenditures
Electrolyser/fuel cell capacity
Carbon capture and storage
Carbon dioxide
Direct current
Dutch continental shelf
Deutscher Verein des Gas- und Wasserfaches (German association for gas and water)
Earnings before interest and tax
Erneuerbare-Energien-Gesetz (German renewable energy act)
Enhanced gas recovery
Enhanced oil recovery
European Union
European Wind Energy Association
Free cash flows
Geometric Brownian Motion
Wind energy capacity
Gigawatt
Water
Hydrogen sulphide
High voltage direct current
Internal rate of return
Kilowatt hour
Liquefied natural gas
Monte Carlo simulation
Megatonne
Medium voltage alternating current
Megawatt
Microvolt
Normal cubic metre (volume at temperature: 0 °C and pressure: 1.01325 barA)
Net operating profit less adjusted taxes
Net present value
National Renewable Energy Laboratory (United States)
North Sea Area
Oil and gas
Convention for the Protection of the Marine Environment of the North-East Atlantic
Polymer electrolyte membrane
Platinum group metals
Research and development
Real option valuation
Stimulering duurzame energie (Dutch incentive scheme for sustainable energy)
Synthetic natural gas
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TDS
TQM
TSO
TTF
UKCS
USD
vol%
Total dissolved solids
Total Quality Management
Transmission system operator
Title Transfer Facility
United Kingdom continental shelf
United States dollar
Volume percent
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1. Introduction
To argue that the North Sea Area (NSA hereafter) - that is the North Sea itself combined with the
adjacent regions and provinces along the Belgian, Netherlands, German, Danish, Norwegian, Scottish
and English coasts - is a prominent energy hotspots of Europe and probably worldwide, is probably an
understatement. Firstly, 70-75% of all primary EU (plus Norway) energy production from fossil and
renewable sources, comes from North Western Europe. This is the equivalent of some 760 million tons
of oil p.a. (as of 2011) (EC, 2013, p. 33). Just over 60% of the energy demand of the EU and Norway,
comes from the same region (p. 71). Thus, the energy system of North-Western Europe represents
some two thirds of Europe’s and 6% of the world’s energy system.
Also, many of the challenges the EU energy system is facing are strongly felt in the NSA. For instance,
North-Western Europe faces a rapid decline in nuclear capacity, on one hand, and a rapid build-up of
renewable capacity on the other. A striking energy transition development is taking place in the NSA
where, during the next few decades, some 600 oil and gas platforms will have to be dismantled
because exploration and production of fossils is ending. In addition, during the same period, renewable
offshore wind capacity, of the order of 50-100 GW, is scheduled to be installed in the same area. This
constitutes a massive demonstration of energy transition and energy innovation. Similarly, in the
regions around the North Sea innovative renewable and traditional energy production capacity is
extending rapidly.
What moreover makes the NSA quite unique in energy terms is that the region faces all the crucial
stages of the energy transition ranging from fossils to renewables. While on the one hand the region
hosts the most prominent fossil reserves and production facilities of Europe, it on the other hand also
hosts considerable renewable capacity both onshore and offshore. Few areas will show such a
dramatic shift from fossil to renewable as the NSA does. On the one hand NSA oil and gas production
reached its peak by about 2000 and is expected to decline to much lower production levels during the
next about 20 years. In fact the process of decommissioning oil and gas platforms that have run out of
production has already started. This contrasts sharply with the massive investment in new renewable
capacity and related grid services in the NSA. As of 30 June 2015, cumulatively, there are 3,072 offshore
wind turbines with a combined capacity of some 10.4 GW fully grid connected in European waters in
82 wind farms across 11 countries1, including demonstration sites (EWEA, 2015). Offshore wind
capacity projections by EWEA suggest that the size of this capacity can grow to levels of between 19.5
and 28 GW by 2020, and according to the central scenario about 23.5 GW (EWEA, 2014). Also virtually
all types of renewable technologies can be found in the region at any stage of the technology cycle,
ranging from hydro capacities in Norway, or offshore and onshore wind, to solar, green gas and tidal
energy production with the help of all kinds of technologies at the Danish, Scottish, German and
Netherlands’ coasts.
It is therefore fair to say that the next few decennia – but the process in fact already started since
about the turn of the millennium - the NSA is likely to simultaneously witness on the on hand the
highlights of the dramatic massive gradual exit of the fossils and on the other hand the impressive
1 Note that this offshore area contains all European waters; almost all of the capacity mentioned is, however, located in the NSA.
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entry on the scene of the various types of renewable energy technologies with probably a dominant
role for wind energy.
Yet we have to be careful not to mentally stick to the seemingly obvious picture that the NSA is a
metaphor for a world where the old fossils will just have had their time and must leave the scene
obviously without leaving any traces of their former prominent presence, while the new heroes, the
renewables, take their place as the champions of the energy system of the future. The one comes, the
other goes: ‘le roi est mort, vive le roi’. Such a simplification would be misleading and potentially
dangerous. The reality of the last few decades has learned that the energy transition simply is not a
quick fix where one energy source is replaced by the other. It is rather a painstaking delicate process
of gradual change that requires careful guidance, coordination, collaboration, flexible policies,
continuous research and testing, integrated modelling and proper institutional frameworks in order to
assure that while via technological progress, innovation and investment the transition towards greener
technology gradually takes it shape, the ultimate services the energy system continuously has to
deliver to society – affordable, reliable and increasingly sustainable energy – will remain available all
the time.
In this report we will ask ourselves if the complex process of the EU energy transition that – given the
EU 2050 mitigation target of having achieved by then a nearly carbon neutral economy – would
basically need to be largely completed in less than two generations, may benefit from collaboration
between the fossil and the renewable energy sector. Are there win-win cases to be explored that have
the potential of not only making the energy transition cheaper for society and more efficient but also
more effective, that is without slowing down the timeframes aimed at? In answering that question we
will zoom in on the NSA hotspot for the simple reason that, as argued before, all the various
components of the energy transition can be found there in an area that is manageable not only in
terms of size and scope, but also is an area that shares a long and deep history of exchange, trade,
migration and sometimes hostile sometimes friendly but always intensive interaction between the
people living in the North sea surrounding areas.
In order to research if win-win potentials between NSA fossil and renewable energy activity can be
identified, it is important to recognise current issues, weaknesses and bottlenecks.
As far as the fossil sector is concerned typical issues addressed in a sector in decline are: what are the
optimal time profiles of (remaining) production; at what moment in time has the end of the NSA oil
and gas production business case for the traditional companies been reached; when should platforms
be transferred to other companies (who still see some commercial value in its use) or dismantled; how
should the decommissioning process be organised, and are there any specific logistical, legal,
ecological, safety or societal acceptance issues that need to be addressed that are related to such
decommissioning; what financial reservations have to be made to cover the costs of decommissioning
and what are the anticipated costs; are there alternative uses of the existing platforms, constructions
and related infrastructure, etc.
As far as the renewable activities are concerned, typical issues and challenges are:
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Grid balancing issues due to renewable supply intermittency. The intermittency of some
renewables, wind and solar in particular, may cause mismatches between supply and demand
time profiles, and therefore considerable balancing challenges in the grid. Various solutions to
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the issue have been suggested, such as grid extension, demand management, as well as
various storage options, but all suggested solutions will require additional investment.
Back-up capacities. Such capacities are needed if renewable supply is insufficient to meet
demand. Recently, however, increasingly the business case of such back-up is questioned,
because the greater flexibility, persistent interruptions in supply and the impact of price
volatility may cause investors to hold back on such back-up capacity investment.
Infrastructure capacity financing. Infrastructure investment needs due to the intermittent
renewable energy capacity extensions can be substantial. For the NSA as a whole investment
needs run into the billions of euros. It will not always be easy and simple – given the (regulated)
tariffs for transport and storage services – to get such investment financed. Even if such
investment is in principle a public responsibility, such financing may be difficult.
Lack of coordination. Because the NSA region covers a range of different countries, the optimal
design of the NSA energy system and related investment requires international coordination.
This is the more necessary as the existing but also new rules, regulations and laws are on the
whole still based on national priorities. So far, a number of bodies has been developed to deal
with coordination issues, but serious and powerful triple-helix organisations for the whole NSA
region are still missing. This explains why the EU is currently seeking to establish regional
authoritative bodies that have the capacities to take up such a coordinating role.
The oil and gas industry in the NSA is also facing a number of challenges:
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The first issue is to wind down production and get to the stage of decommissioning. Obviously,
it is a complex technical and economic issue for the oil and gas exploration companies active
in the NSA to plan the ongoing but declining production activities: how much production will
take place when and where? Related issues are if, and to what extent, remaining exploration
options will be outsourced or left to other producers.
A second issue is the final stage of decommissioning where, as a principle, the existing
infrastructure will need to be removed, and the original situation restored. Such
decommissioning can not only be costly, but also complex from a technical and environmental
perspective. It can be interesting to see what options could be available in this regard that
could create a win-win situation between business and environmental interests.
The final issue is somewhat more abstract but involves the challenge for the traditional oil and
gas production companies to redefine their role as energy producers during and after the
energy transition. Are such players simply leaving the scene once production has been finalised
and decommissioning is taken care of, or is there still a role for the same players in a world
where new forms of renewable energy have taken the lead?
The above issues that both the renewable players and the traditional oil and gas production companies
are facing may provide some basis for smart sustainable combinations. That is, combinations of
activities of the various NSA players, such that win-win situations occur. Examples of such
combinations are:

The combined use of existing infrastructure. It would be challenging to investigate whether
the renewables sector may be able to save on new infrastructure investment, by using existing
infrastructure that is not yet technically written off as its use by oil and gas companies
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diminishes: is it feasible that such infrastructure can be used to store renewable energy or to
transport energy supply from renewable sources to onshore or other destinations?
The combined use of storage facilities. Just as with regard to infrastructure, also storage
facilities, already existing as part of the traditional oil and gas production activity, can be used
by the renewables sector to, at least in part, resolve the balancing and pricing problems
intermittency may cause.
Energy conversion activity. Much of the energy sector activity is dealing with energy
conversion, i.e. converting one form of energy into another form more suitable for end use. In
fact, renewable energy production is based on converting the natural energy from wind and
solar into electricity, etc. Such electricity eventually will be converted again, probably via more
than one conversion step, into a form that is most suitable for its final use. Most of the
conversion usually takes place onshore, but it is interesting to investigate if, and to what
extent, offshore conversion activity – e.g. converting renewable power into green gases – may
provide a business case, and also to what extent this may benefit from collaboration between
the traditional NSA oil and gas sector and the new renewable energy players. Interesting
combinations in this regard could involve the option for ships in the NSA to refuel at the
platforms with renewable energy (e.g. green hydrogen, green LNG, green ethanol, etc.,
produced in the NSA).
The ecological value of the NSA region is very substantial. This explains why the oil and gas
companies must behave very carefully in terms of surveying and reducing the adverse
environmental impact of their actions. Also, positive environmental activity is very important
in this regard. The same obviously applies to the new energy activities in the NSA region. This
raises the issue to what extent the various energy players may work together in setting up joint
actions to support the NSA environment and to enhance public support. Examples could be
joint activity on ‘green reefs’, environmental research on marine life, etc., joint projects for
informing the public about NSA activity, joint pilots, etc.
A priori, win-win situations from which all NSA players, both the traditional ones and the new ones,
could benefit seem likely to exist. It would be odd to assume that good coordination and collaboration
would not be capable of producing joint activity benefiting all. The challenge is of course to turn such
options into reality. This is the more so because, again a priori, such joint action will not easily come
off the ground. Obvious bottlenecks may be that such projects will be: complex and therefore require
the involvement of many players; not easy to coordinate, because both public and private interests
are at stake, involving triple-helix players from different countries; characterised by various
externalities, meaning that positive impacts cannot be monetised by the investors in the projects
themselves; not easy to finance because of the various reasons just mentioned: who is responsible,
how will the various players deal with picking up the bill, which consortium will finance on the basis of
the overall societal rather than direct business impact, etc.?
The purpose of this report is to make a first step in investigating if a concrete first win-win NSA initiative
can be developed. It starts from the assumption that a small pilot, in which traditional oil and gas
producers and renewable players work together, may be a good start of a development towards more
substantial win-win collaboration. Therefore, a pre-feasibility study has been carried out to see if
energy conversion activity can be economically feasible, technically possible, and publicly acceptable.
Such conversion involves that – to put it simply – renewable power is converted into a green gas on an
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existing NSA oil and gas facility and subsequently stored and transported onshore via existing
infrastructure.
To put this pre-feasibility study into the overall perspective of the NSA energy system, and to get some
feeling of what the long-term contribution of smart sustainable combinations between the traditional
and new energy players to the overall energy supply in North-western Europe could be, the following
chapter (chapter 2) will provide an overview of the potential benefits of NSA smart energy
combinations. Thereafter, in chapters 3 and 4, we will respectively zoom in on the economic and
business issues related to a possible smart combination pilot, and its potential technical issues. Finally,
in chapter 5 an overview will be provided of possible further steps towards a first smart combination
pilot project.
2. Smart sustainable combinations: overall perspectives
Oil and gas has been a major industry in the NSA for over 40 years. On the Dutch Continental Shelf
(DCS), offshore production activities started in the late 1970s. Today there is extensive offshore
infrastructure associated with the exploration and production of oil and gas, including platformmounted production facilities and networks of pipelines. In 2014, the average age of, for instance, the
Dutch North Sea structures was 24 years. Therefore, many of these structures are now reaching the
end of their productive life or will do so in the coming 10 years.
Operators are under legal obligation to decommission the infrastructure once production has ended.
To illustrate: alone in the UK Continental Shelf (UKCS) there are 470 oil platforms, more than 5,000 oil
wells and 10,000 kilometres of oil and gas pipelines. In the coming decades an average of 15 to 25
production platforms per year will be dismantled. The estimated cost of this massive clean-up
operation amounts according to energy consulting firm Wood Mackenzie to more than 21 billion euros
on the UKCS.
As far as the overall NSA is concerned, during the next few decades some 500-600 installations need
to be abandoned and dismantled, a task that has to be carried out in a harsh maritime environment
and represents engineering and financial challenge. According to some experts, for the total NSA
decommissioning costs would amount somewhere between 28 and 39 billion euros. Other experts
estimate the technical costs for this task to be 50-100 billion euros in the next 40 years, while noting
that such costs will probably be covered to a substantial degree by governments (as a result of tax
deduction and co-ownership schemes).
Box 1. Oil and gas production and offshore wind energy deployment: situation on the Dutch Continental Shelf
In the DCS there are about 160 platform installations and over 2,000 km of pipeline that eventually will
have to be decommissioned (OSPAR, 2015). One of the currently investigated options for smart
sustainable combinations in the energy transition is the use of platforms for offshore power-to-gas
installations. The idea behind it is to convert offshore wind energy into hydrogen and/or methane by
electrolysis and possible post-synthesis to methane, and transport the gas via offshore pipelines
onshore. By doing this, not only decommissioning costs for the platforms are mitigated, but also
investments in offshore electricity cables or storage capacities can be avoided by using existing
infrastructure. The Dutch electricity TSO TenneT estimates the investment costs for the electricity
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connections of 3,450 MW offshore wind capacity to be installed until 2023 at € 2-3 billion
(WindenergieCourant, 2014).
The first wind farms in the Dutch North Sea have been built in the Offshore Windpark Egmond aan Zee
(8 miles off the coast of Egmond) and the Princess Amalia wind farm outside the 12-mile zone. They
have a capacity of 100 and 120 MW and cover an area of 26.8 and 16.6 km² respectively, including a
safety zone of 500 meters around them. These parks are also called ‘round 1-parks’. In addition,
permits have been issued for the construction of new wind farms, called ‘round 2-parks’. Three parks
will receive funding and will be built in the coming years. Through a national plan, the government has
specified locations where the new wind parks (‘round 3’) can be built. It has decided that three offshore
wind farm zones will be used as locations for the deployment of the 3,500 MW new offshore wind
power capacity as agreed upon in its national Energy Agreement (‘Energieakkoord’): Borssele (1,400
MW), South Holland coast wind farm zone (1,400 MW), and North Holland coast wind farm zone (700
MW) (Rijkswaterstaat, 2015).
Figure 1 illustrates the information above graphically, and shows that some smart sustainable
combinations between oil and gas platform activity and new offshore wind activity seem feasible
location-wise. The green arrows indicate in which zone direction post-2020 renewable energy
generation will be concentrated, opening up new options for smart sustainable combinations.
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Figure 1. Netherlands government's vision on offshore wind energy deployment (I&M and EZ, 2014).
Currently, a parliamentary discussion is ongoing on the issue whether future offshore wind farms will be
located closer to the coast (between the 10 and 12 mile zones).
Current regulation – the OSPAR Decision 98/3, a regulatory framework under OSPAR Convention and
national legislation - requires that disused offshore installations have to be fully removed to shore for
waste treatment and disposal. However, the reuse of these installations is allowed if it can have
another legitimate purpose in the maritime area authorised or regulated by the competent authority
and if the new owner of the structure accepts the liability for eventual decommissioning.
Currently, there are ongoing discussions about how to deal with disused oil and gas installations. In
the light of these discussions, it is possible that the OSPAR regime will see some adjustments when it
will be renegotiated for a next phase (an event expected for 2018). Given the current legal framework,
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possibly the reuse of platforms for other purposes may be an acceptable option under specific
circumstances.
One may ask oneself not only why such reuse of platforms e.g. for power-to-gas conversion (and/or a
‘green reef’) will provide an interesting win-win option, but also what could make such an offshore
conversion option more interesting than similar options onshore. With respect to the latter, some
arguments can be provided why offshore conversion could provide a better alternative:
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2.1.
Offshore conversion may lead to postponing of decommissioning. This in itself may create an
economic value because of the discounted cash flow of the postponed decommissioning
reservations made by the oil and gas companies. Given the cost data provided above, such
cash flow can be substantial.
Offshore chemical conversion may benefit from the use of the existing about 10,000 km of the
oil and gas pipeline network in the NSA to transport the gasses or possibly fluids to their
onshore destinations. Insofar as such existing infrastructure can be used, the investment in
new power transmission capacity may no longer be necessary. This may generate considerable
positive externalities.
The NSA itself is at the centre of a large number of key European industrial, energy and
chemical complexes in various surrounding member-states. Chemical products generated
from renewable energy, containing considerable energy and being easily storable and
transportable, can therefore be a new green and sustainable feedstock from many of such
industries. Indeed, the North Sea feedstock could, for instance, create the base of a new green
chemical industry in North-Western Europe.
Issues of public acceptance, which may easily arise onshore, e.g. because of concerns on
explosion and health risks of the fluids and gases produced, may be much less severe if
conversion activity takes place offshore and therefore far away from populated areas.
Large-scale storage conditions are relatively favourable in the NSA because of the large
number of nearly empty small gas fields in the area. Thus, not only for public acceptance
reasons, but also for technical reasons storage may be relatively easy and cheap.
Scenarios
In order to get a better understanding of the overall long-term future perspective on the role of energy
conversion, and power-to-gas in particular, in the NSA energy system, a number of scenarios have been
designed for different time-frames, illustrating how the technology could possibly evolve. We
distinguish between two short-term scenarios (one with and one without ongoing oil and gas
production), a medium-term scenario and a long-term scenario.
2.1.1. Short-term scenarios
The simplest short-term scenario, and in fact the possible beginning of smart energy combinations,
could be a small conversion pilot project on an existing platform that is still operational. Such a pilot
could be considered as the first step in the offshore power-to-gas process and would consist of a
demonstration plant where the technology and all needed standards and procedures are tested only.
In this case the platform is still functioning so that only part of the platform will be dedicated to powerto-gas. This means that the electrical hub, if at all included in the pilot, will be present outside of the
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platform. Only the electrolyser and the necessary equipment are present on the platform, including
possibly: a post processing plant to purify hydrogen; a small hydrogen storage where the hydrogen
should be cooled down; and a water treatment plant (water will be used as a feedstock for the
electrolyser and for cooling purposes).
The electricity needed for the electrolysis process could be brought from the nearest source of wind
energy; it could be provided via an AC/DC transformer or via an MVAC collecting station (in the latter
case an AC/DC transformer station should be installed on the platform). If such electricity supply
would, however, be too complex or too costly, the electrolyser can use the electricity generated by the
gas or diesel generator generally located at the platform. The power demand of an offshore installation
is usually substantial (in the range of a few to hundreds of megawatts). However, because many
offshore generators have overall efficiencies as low as 20-25 % under the best of conditions (ABB,
2013), fuel consumption, maintenance frequencies, and emission levels often are unnecessarily high.
So, whenever power demand is low and the generators are working under-power, a part of the
generated electricity can easily and mostly cheaply be used for the electrolysis process. In fact, this
manageable source of electricity may be used to service the optimal capacity factor of the electrolyser
and to also reduce cold start-up problems.
A next pilot to be set-up in the short term which can be considered a step further could involve
connecting, for testing purposes only, a wind farm to an existing platform that otherwise would need
to be decommissioned. At the platform, hydrogen will be generated that will be transported through
the natural gas grid that is already connected to the platform. Storage facilities are used to store
hydrogen seasonally.
The power for the electrolysis can, for instance, be assumed to come from a, say, 300 MW wind farm
located near the platform. An electric hub will be built at the platform where the AC current generated
from the turbines will be transformed to DC current. A portion of the incoming electricity will be
allocated to a PEM electrolyser where the electricity will be transformed to hydrogen. The rest of the
electricity will be transported via HVDC cables to shore. The hydrogen generated will be cooled down
and purified before being added to the gas grid. The excess hydrogen produced will be stored in
underground salt caverns located below the platform for seasonal storage (if needed).
Since gas demand is fluctuating on a daily and seasonal basis, hydrogen storage should be introduced
to overcome this barrier, or else the production of hydrogen would be limited to the lowest gas
demand during the year (taking into account the maximum hydrogen concentration limit accepted).
By adding both a daily and seasonal storage one can keep the production of hydrogen constant during
the year. All the necessary water needed for the electrolyser as feedstock and for cooling purposes will
be generated from a water treatment plant located offshore.
By this stage the existing NSA DC infrastructure only consists of several existing HVDC cables
connecting different countries in the NSA such as the 700MW NorNed Connection connecting Norway
to The Netherlands and a small number of Offshore HVDC convertor platforms that several wind farms
are plugged to, such as the eight offshore platforms currently built by TenneT in the North Sea
implementing the offshore expansion targets set by the German federal government (Koers, et al.,
2014).
15
2.1.2. Medium-term scenario: decarbonizing the transportation system
A scenario for the medium term (for a graphical illustration, see Figure 2) could for instance be a fullblown pilot in which a, say, 600 MW wind farm is connected to a platform. Synthetic natural gas (SNG)
would be generated at the platform and added to the natural gas grid. Depleted gas field capacities
would be used for storage of CO2 and SNG (if needed).
Figure 2. Graphical illustration of medium-term scenario
The wind farm would be connected via an electric hub to transform the MVAC electricity to HVDC. A
portion of this DC electricity will be allocated to the electrolyser to produce hydrogen. The rest of the
electricity will be transported via a HVDC cable to shore. The produced SNG will be stored at the
platform in a small buffer storage to be cooled down before being injected in the gas grid. Insofar as
the produced SNG is intended for fuelling ships on the site, or for the automotive industry, and insofar
as the related gas demand patterns do not significantly change during the year, long-term storage will
not be needed in this scenario.
In this medium-term scenario it could be feasible to include CCS technology, whereby carbon is used
for a mix of: offshore methanation (obviously requiring a methanation unit to be established at the
platform; the heat generated from the methanation process could be used for water treatment
purposes, which could increase the efficiency of the overall system and reduce the energy needed for
water purification); enhanced oil recovery (EOR; more oil and gas can be extracted from the nearly
depleted fields next to the platform, thus increasing the financial income from these fields); and
storage in offshore depleted gas fields. The latter may enhance public acceptance of CO2 storage, as
compared to alternative onshore storage options. Obviously, the platform could be used to collect and
further compress the CO2 before storage.
2.1.3. Long-term scenario: wind as a base load
In this long-term scenario, we move from a full-blown pilot project towards a demonstration project.
In this scenario, again, hydrogen will be produced at the platform but now at a larger scale. Part of this
hydrogen will be transformed back to electricity via a fuel cell located at the platform. The electricity
generated by the fuel cell will turn the intermittent wind-based electricity into base load energy. The
remaining hydrogen will be mixed with natural gas with high concentration levels, e.g. up to 50%
(NATURALHY, 2009), to be possibly separated again later onshore (while an acceptable concentration
will be kept in the natural gas grid).
16
Figure 3. Graphical illustration of long-term scenario
The process is illustrated in Figure 3 in which a, say, 600 MW wind farm is connected to the platform
via an electric hub to transform the MVAC electricity to HVDC. A portion of this DC electricity will be
allocated to the electrolyser to produce hydrogen. The rest of the electricity will be transported via a
HVDC cable to shore.
The hydrogen will be used in a fuel cell to generate electricity whenever electricity is needed or at least
the price of electricity is sufficiently advantageous. The excess hydrogen will be transported to shore
via an existing natural gas grid. Once the gas is onshore, a separation plant will extract pure hydrogen,
which will be utilised by the industry or mobility sector. The rest will be kept for admixing to the natural
gas grid to the extent that gas demand and the related hydrogen concentration limit allow for this.
At this stage it is expected that wind energy is heavily deployed in the NSA and that the offshore HVDC
grid has been established: several neighbouring wind farms are clustered and connected together to
shore, and countries are better interconnected. For this reason we will assume that, in this scenario,
additional DC power will be used from other wind farms via the connected DC grid. This will increase
the capacity factor and efficiency of the electrolyser and reduce the cold start-up problems. Salt
caverns adjacent to the platform may be used for long-term hydrogen storage.
2.2.
Quantitative potential impact of the scenarios
The above scenarios only served as a description of how the power-to-gas technology could gradually
evolve offshore, starting from a simple testing pilot, but developing into fairly large-scale
demonstration projects. Obviously, the scenarios are just an illustration of what could happen; all kinds
of different scenarios would be equally feasible. Starting from the above scenarios, the question raises,
assuming that power-to-gas is gradually extending across the NSA and taking serious proportion based
on sound business cases, what the order of magnitude of impact of this technology could be on the
overall NSA energy system. Therefore a simple mathematical conversion model has been developed
(see Annex 1), some illustrative results of which, if applied to the various scenarios, are the following.
2.2.1. Short-term scenarios
The purpose of this exercise is to calculate the required electrolyser capacity to cover the demand of
hydrogen when 0.5% hydrogen is added to the natural gas grid. More specifically, the purpose is to
17
calculate how much offshore electrolyser capacity would be required to provide an x number of
households with the amount of hydrogen to be included in the gas volume that they usually need, and
to calculate how much hydrogen storage capacity would be needed to service this. With regard to the
electrolyser process, we assumed that only renewable energy will be used for the electrolysis if the
wind speed level surpasses a threshold beyond which curtailment of wind energy would be required;
this obviously limits the number of hours at which the electrolyser is operational (outside the
operational hours, the electrolyser is kept running at a very low level with the help of power from the
platform generator to avoid cold start-up issues. The same generator also secures full electrolyser
capacity when operational).
The number of hours during which the electrolyser is operational depends on the number of wind
energy curtailment hours, which in their turn again depend on the installed capacity related to
projected demand and grid capacity. A calculus based on the 2020 projections for the Netherlands
indicated that a number of about 510 hours (or some 6% of the time) seems to be the most feasible
figure, assuming that by then 12 GW wind capacity will be installed. For the longer-term scenario in
which the projected 26 GW would be realised by 2050, the number of curtailment hours would,
according to the same source, raise to 1119 (or some 13% of the time).
Obviously, the results of the calculus will change negatively in proportion if the 0.5% limit would be
raised. The calculus is based on Netherlands data (assuming 1700 m3 gas consumption per annum per
household). However, assuming fairly similar wind profiles, household level gas demand profiles, and
related wind capacity ambitions and grid availability across the whole NSA, the results can be
considered to be broadly indicative for the overall NSA.
The two figures below represent the model results by indicating the relationship between the overall
electrolyser capacity, the number of households served with hydrogen, and the required hydrogen
storage capacity. It shows for the 510 curtailment hours case that overall 65MW of electrolyser
capacity can cover the hydrogen demand of 1.8 million households. Only 45MW is needed in the case
of 1119 curtailment hours. The corresponding storage capacities are 542 and 578 tonnes of hydrogen
respectively; the latter figures are fairly large because only one storage cycle is assumed, i.e. there is
only one charge and discharge during the year. Obviously, this storage capacity will come down if
storage cycles become more frequent.
Figure 4. Electrolyser capacity vs number of households for 510 curtailment hours
18
Figure 5. Electrolyser capacity vs number of households for 1119 curtailment hours
2.2.2. Medium-term scenario
In this scenario, the methanation process is functioning offshore generating SNG or green gas that can,
for instance, be used in mobility as one of its most promising niche markets (see also section 3 on this).
The question arises how much electrolyser (and related methanation) capacity will be required to
eventually fuel an x number of cars fuelled by green gas. In the calculus with the help of the conversion
model (annex 1), the same assumptions were used as in the former case, and in addition the
assumption was made that an average car consumes 0.06m3 of gas per km, and has an average daily
mileage of 50 km. The power produced by the platform generator is no longer assumed to get to the
electrolyser
In the case of 1119 curtailment hours per year, an electrolyser capacity of 60 MW (250 MW) will be
sufficient to satisfy the annual demand of 2,000 cars (9,000 cars). See Figure 6 for a graphical
representation.
Figure 6. Green gas production vs demand with 1119 curtailment hours
If the electrolyser and methanation unit would be operational nearly full time (assume some 80% of
the time), then some 20,000 cars could be fuelled with the help of an 80 MW electrolyser and
methanation unit combination. Figure 7 shows the impact of a longer operational time of the 80 MW
electrolyser and methanation unit on the number of cars served.
The above calculus would imply that if 5% of the about 8.9 million cars in the Netherlands would be
completely fuelled by SNG/green gas from the North Sea offshore conversion units, this would require
19
some 22 platforms each hosting a 80 MW electrolyser and methanation unit combination running near
full time.
Figure 7. Effect of wind penetration on an 80 MW electrolyser
2.2.3. Long-term scenario
In this scenario, we assume that offshore electrolyser/fuel cell capacity will be used to diminish the
intermittency of the power generated by the surrounding offshore wind farms. Basically surplus wind
is turned into hydrogen via the electrolysers, and if wind capacity is less then demand the hydrogen
stored will be activated by using fuel cells to turn it into power. The question arises how much
electrolyser/fuel cell capacity (CE) would be required to completely stabilise the available wind power
capacity by turning the intermittent wind energy capacity (GE) fully into baseload capacity. This
calculus has been done for a hypothetical 600 MW wind farm, assuming that the CE will always be able
to deliver power and therefore never will be short of hydrogen. In case the control strategy is satisfied
and there still is an excess of hydrogen, this hydrogen will be admixed to the natural gas grid. Since the
electrolysers and fuel cells are relatively capital intensive, their utilisation rate and capacity factor will
be maximised with minimum avoidable downtime.
Figure 8 illustrates the hydrogen surpluses given a range of CE values. The highest capacities at which
there will be no hydrogen shortages (deficits not projected in the figure) are about 200 MW and 270
MW respectively. The electricity outcomes of such two CE values are illustrated in Figure 9 and Figure
10, respectively. They show that while a CE value of 200 MW is capable of turning a substantial part of
GE into baseload power supply (the graph shows a base load of 200MW and some peaks to 540MW –
the latter figure is some 10% less than the 600 MW wind farm capacity due to wind farm wake and
AC/DC losses), a full stabilisation of capacity can be reached at a CE value of 270 MW.
20
Figure 8. Excess generated hydrogen vs electrolyser capacity
Figure 9. Electricity outcome for a 200 MW system
Figure 10. Electricity output for a 270 MW system
Given the above calculus, one may ask oneself how much GE and CE would theoretically be required
to completely satisfy all possible situations of peak electricity demand of a country such as the
Netherlands. In such a hypothetical case, this country would be completely served by offshore wind
power which in its turn would be completely turned into predictable baseload via the capacities of the
electrolyser/fuel cell combinations. In the current situation, the Netherlands’ maximum electricity
demand peaks at 19 GW. Extrapolating the above findings suggests that a GE of 42 GW and 70
platforms with 270 MW CE would be required. Obviously, this is an extreme case, because various
21
other sources of power supply, both onshore and offshore, are available as well, and because 100%
guaranteed baseload supply for all peak situations may not always be required. The calculus, however,
gives some idea about the CE capacities that could be needed under specific conditions.
3. Economic and business issues
So far, a series of pilots has been initiated in North-Western Europe, all onshore, testing various
elements of power-to-gas conversion, sometimes combined with gas-to-power activity. For an earlier
overview of pilots, see Gahleitner (2013). Usually, pilots are not required to be fully commercially
feasible. After all, pilots are meant to test the feasibility of specific new technologies and therefore act
as a possible precursor of next-stage commercial application. Also, pilots may deliver externalities,
either positive or negative, which are economic values that do not accrue to the pilot investor. Pilots
can also be used to get a feeling of the possible business perspective of the technology studied, and
that is why in this section it will be tried to do so for a hypothetical offshore power-to-gas/gas-topower project.
The method used to assess the project’s economic feasibility is based on a standard net-present-value
(NPV) analysis (for a more extensive description of both the method and (the sources of) the data, see
Annex 2). The costs of investing in electrolysers, fuel cells, methanisers and fuel stations are typically
driven by the CAPEX costs and by the prices of energy, hydrogen, oxygen, synthetic gas, and fresh
water.
3.1.
The power-to-gas end-use options
Table 1 provides an overview of the main output options for power-to-gas activities. These options
represent how energy generated by the electrolyser (and fuel cell) conversion unit can be allocated in
terms of end use. It seems obvious to assume that, in actual practice, a mix of options may be the most
optimal, even at a given hydrogen/oxygen price, because other relevant variables show a stochastic
pattern. As the results of the NPV calculation based on the real options concept below indicate, this
assumption is corroborated by the model findings: it is often economically optimal to diversify end use
to some degree.
Table 1. Overview of main markets for hydrogen and their characteristics
Usage
Demand
Price
Assumption
Source
1. Hydrogen-topower
Variable
demand
Simulated
Hourly constrained by grid line
capacity, seasonality and hour.
Storage issues and conversion
losses.
Veijer (2014)
Price depends on transport
mode. No regulations and low
compression losses.
Veijer (2014)
2. Hydrogen
feedstock
Yearly
demand of
2,496 million
kg
€ 2-3/kg
€ 5-8/kg
Jansen (2015)
Moes (2015)
€ 3.20/kg
22
3. Hydrogen infeed
Fixed
demand
4. Hydrogen to
road mobility
Underdeveloped and n/a offshore.
5. Hydrogen to
shipping
Underdevelo
ped.
€ 4.435.68/kg
Required installed capacity of
electrolyser of min. 2 MW. No
regulations and low
compression losses.
Loisel, et al. (2015);
Moes (2015)
6. Synthetic gas
No fixed
demand
€ 1.061.95/kg
Unconstrained by regulation.
Lower risk of flammability.
Conversion losses.
Jansen (2015)
3.2.
€ 1.061.95/kg
Regulations and pipeline
capacity constrain hourly infeed
Jansen (2015)
In assessing the economic feasibility of the first option with the help of the model as described in Annex
2, the assumption has been made that a PEM fuel cell is used to convert hydrogen into power. Staffel
and Green (2009) and Taljan et al. (2008) estimate the investment costs of PEM fuels cell technology
to amount to approximately € 1,000 per KWh. In order to relate the fuel cell capacity to the assumed
capacity of the underlying electrolyser, it has been assumed, like by Veijer (2014) and Wouters (2014),
that the required capacity of PEM fuel cells is 0.375% of that of the electrolyser. The reason is that the
fuel cell is assumed to operate some 16 hours per day against some 8 hours for the electrolyser, and
that the efficiency of the alkaline electrolyser is 75% of capacity MW.
3.3.
Option 2: Hydrogen as a feedstock for the chemical industry
For the Netherlands’ situation, the annual demand for hydrogen by the chemical industry is estimated
to be some 2.5 million kg (Jansen, 2015). According to Veijer (2014) a daily quantity of 182-238 Nm³ of
hydrogen and 91-119 Nm³ of oxygen can be produced with a 1 MW electrolyser. There is no public
transparent market for hydrogen, nor for oxygen. So, there are no price lists available. Jansen (2015)
assumes an oxygen value of € 0.085 per kg. The sales price of hydrogen depends on a number of
factors, such as the pressure, quality and method of transport. Although exact price estimates are not
available, Veijer (2014) found the following price ranges: bulk 200 bar (trailer) € 5-8/kg and pipeline €
2-3/kg.
23
Figure 11. Hydrogen pipeline networks of ‘Air Liquide’ and ‘Air Products’ (Perrin, et al., 2007).
Figure 11 provides an overview of the underground pipeline transport of hydrogen and oxygen owned
by Air Liquide and Air Products near Rotterdam. Linking a possible offshore plant with one of these
pipeline systems would involve immense costs. To limit such costs, one could try to establish a link by
using existing offshore pipeline structures, if technically feasible. Section 5 provides a comprehensive
overview of the offshore pipelines that are currently out of usage , and could possibly be used for
hydrogen/oxygen pipeline transport.
Although the transport of hydrogen and oxygen by pipelines may on the longer term provide
interesting avenues for future large-scale introduction of hydrogen in the economic system, in this
report such facilities are not considered, as they are seen as being too massive and costly for pilot case
assessment. Instead, the transport of hydrogen by trucks or ships could provide an interesting option
for small-scale applications. For instance, André et al. (2014) studied the capital and operational
expenditures of each transport mode and concluded that until 2025 truck and cryogenic delivery is the
economically preferred option. This finding is based on the observation that truck delivery has low
initial investment costs while also having the flexibility to deliver small and infrequent amounts of
hydrogen.
The hydrogen price received by the supplier is assumed to be € 3.20 per kg (Moes, 2015). In reality,
hydrogen transported with trucks and/or ships will have a cost price which is higher, due to the
relatively high costs of such bulk transport: the literature mentions prices in the range of € 5 to 8 per
kg after bulk transport (Veijer, 2014). In this study, we assumed that the relevant price for the producer
is based on a pipeline transport mode with some premium, assuming that the additional costs due to
bulk transport can be levelled off onto the end user. Because the hydrogen price assuming pipeline
transport availability is estimated some € 2 to 3 per kg after transport, the € 3.20 per kg figure was
considered to be a fair assumption for our calculus.
A significant feature distinguishing the hydrogen generated by the electrolyser from the traditional
supply of hydrogen based on steam reforming of hydrocarbons (mostly natural gas), is that the former
is a ‘green gas’ whereas the latter is not. It seems likely that in the future in some niche markets nongreen hydrogen will not at all be accepted, or that the green hydrogen will receive a premium price as
compared to the traditional non-green hydrogen. It is still unclear what the order of magnitude of the
premium is going to be and how it may develop into the future, but currently in various NSA member
states subsidy programmes are implemented providing such a premium for a long period (e.g. 20 years
for the German EEG or 12-15 years for the Netherlands’ SDE+ programme). Such premium may vary in
24
size and scope but, for the time being, has been guesstimated to comprise 30% of the hydrogen sales
price. This would raise the future price of hydrogen from € 3.20 to € 4.16.
3.4.
Option 3: Infeed in gas infrastructure
A third option would be the injection of a limited percentage of hydrogen into the existing natural grid
as an admix. The quantity of hydrogen that can be added to the gas grid is limited by law or regulation,
because too much hydrogen may have adverse effects and cause security risks due to e.g. changing
flame stability or degradation of the grid infrastructure (Grond, et al., 2013). The accepted admix of
hydrogen tends to increase in the EU, but still is a national affair. In the Netherlands, for instance, the
total share of hydrogen allowed in the natural gas mix will increase from 0.02 vol% currently to 0.5
vol% by 2021 (EL&I, 2012). In other NSA countries authorities seem to be somewhat more relaxed
about adding hydrogen to the natural gas. In Germany, for instance, the DVGW propagates to allow
percentages up to about 10 vol% (Müller-Syring, 2014).
Assuming a certain accepted percentage of hydrogen admix, the question arises how much hydrogen
can be transported via an existing gas pipeline system. In order to get some sense of proportion, the
following figures may serve as an illustration based on the notion that the amount of hydrogen to be
transported via a grid depends on the diameter of the pipeline and the pressure of the gas. Assuming
a 36 inch pipeline, and assuming a 0.02 vol% restriction, some 150 Nm³ of hydrogen could be
transported per hour, which would be 2,400 Nm³ per day (based on 16 hours delivery). Under a 0.5
vol% restriction, these figures would be 3,750 Nm³ and 60,000 Nm³, respectively.
The current price received for hydrogen infeed in the gas grid, based on the natural gas price in the
Netherlands, amounts to € 1.06 – 1.95 per kg. However, it is expected that ‘green’ gas delivery will
increasingly receive a premium. Based on this expectation, we assume a future hydrogen price to be
received via this option in the range of € 2.50 – 3.44 per kg (Jansen, 2015).
3.5.
Options 4/5: Hydrogen for mobility (shipping and automotive sector)
A next set of options would be the use of hydrogen as a source of fuel for the shipping and/or
automotive sector. Hydrogen is a promising new green fuel for the overall mobility sector, which
explains why a series of new initiatives to more introduce hydrogen in mobility are currently under
way, such as the development of hydrogen cars and the establishment of hydrogen fuel stations in
various NSA member states.
Here, we will primarily zoom in on the potential role of hydrogen as a fuel for the shipping sector. A
development could be that hydrogen fuel stations will be located on various coastal sites, in harbours
or along rivers. An alternative development that could become feasible is that offshore platforms
equipped with electrolyser capacity, will also be equipped with an LNG fuel station such that ships can
take in the LNG at the platforms. Some data on the costs of hydrogen fuel stations are mentioned in
the literature, but such data may be very sensitive to the fact that there still is little experience with
such facilities. Melaina and Penev (2013), for instance, suggest that significant cost reductions may be
achieved soon, but that early commercial hydrogen fuelling stations with a capacity of 240 kg per day
25
would still cost about € 2.5 million2. To further illustrate, if an electrolyser would be fully operational
and if its hydrogen produced would be fully used for fuelling purposes, a 2-3 MW electrolyser would
be able to provide some 450 kg per day.
Currently, hydrogen prices received by the suppliers are relatively high compared to other options, if
that hydrogen can be used for mobility fuelling. Such high prices are in fact needed given the relatively
high investment costs of the fuelling equipment. Jansen (2015) assumes hydrogen fuel prices,
excluding excise duties, in the range of € 4.43-5.68 per kg. Also in this option, it is fair to assume that
the premium for the ‘green’ character of the fuel will increase. It is, for instance, expected that in the
future governmental regulation may stimulate the development of ‘green’ hydrogen as a
transportation fuel by offering tax exemptions. If future hydrogen fuel prices will be fully exempted
from excise duties, which amount to about half of the sales price, this could lead – assuming the tax
exemption is fully recouped by the supplier – to a hydrogen price for the supplier of about € 10 per kg.
The latter figure is in line with the price expectations by Jansen (2015) and Moes (2015).
3.6.
Option 6: Hydrogen to methane gas
A final option would be the use of hydrogen as an input for synthetic gas production, e.g. with the help
of a methanation process. The reason why one could consider this option to be interesting is, for
instance, that the hydrogen is considered too risky to produce large-scale, to store, or to transport via
the existing grid structures. By turning the hydrogen into methane or other syngases, such risks could
be taken away; moreover, there is a long-term experience with handling methane, which may also
cause this to be a better accepted and therefore simpler option, even if the conversion of hydrogen
into methane obviously will not only add costs, but also energy conversion losses.
One of the crucial elements of the conversion of hydrogen into methane is that this so-called Sabatier
reaction requires the input of CO2. Although CO2 may be available as a residual removed from the gas
produced at the platform, the quantity of such CO2 that comes free with the extraction of oil and gas
is usually small. The average content of CO2 emitted by the extraction is usually not more than 2%.
Therefore, access to CO2 input needs to be explicitly dealt with in considering this option. We will
assume that if methanation activity would be initiated on platforms, such methanation will be
chemical, not biological, because the latter option would require too much space given the average
platform surface.
3.7.
Valuation of scenarios
Given the end use options specified above, the question arises what scenario conditions deliver the
best NPV results, and what is the optimal mix of options. In order to make such an assessment, five
scenarios have been developed that differ in the following respects: all scenarios employ a 1 MW
electrolyser, except for scenario E where the capacity has been raised to 2 MW. A fuel cell is not
employed, except for scenario B, where a 0.375 MW fuel cell has been added to the system. Storage
equipment for hydrogen and oxygen is required in scenario A, and to a lesser extent in the other
scenarios. For scenarios D and E a >300kg daily handling refuel station is included in the project. A next
2 Some experts suggest that these cost estimates may still be too low, because of the rather costly character of investment in and
operation of docking facilities for offshore tanking.
26
feature distinguishing the various scenarios relates to the prime end use segment on which the project
focuses in combination with the most likely hydrogen price linked to that destination.
This means that in scenario A the main concept of the project is to try to sell the oxygen and hydrogen
to the chemical industry (option 2 above) against the assumed prevailing price in that sector, i.e. € 3.20
per kg. This concept explains why on the platform, next to the electrolyser, hydrogen and oxygen
storage facilities are required. The overall investment therefore is some € 1 million for the electrolyser
and some € 100,000 for the storage facilities.
In scenario B, the key assumption is that it is difficult to organise serious hydrogen and oxygen storage
capacity on the platform, although some hydrogen storage remains in order to be able to activate a
fuel cell that is assumed to be introduced at the platform. This fuel cell enables the energy to be
transformed into power to be sold via the electricity grid, that is assumed to be connected to the
platform (option 1). In this scenario, also the hydrogen is assumed to be injected in the linked natural
gas grid for direct sale to general use to the extent that the gas grid can absorb the hydrogen (option
3), leaving the residual for the chemical industry (option 2). Considering this combination of options,
including the direct feed-in into the natural gas grid, the required hydrogen storage capacity at the
platform is about 70% less than in scenario A. The assumed hydrogen price in this scenario is based on
a weighted average of the price received if sold to the chemical industry (€ 3.20/kg) and if fed into the
gas grid (€ 1.50/kg), assuming a maximum infeed in the gas grid of 150 Nm 3 per hour, leaving 60 Nm3
per hour for sale to the chemical industry. This leaves us with a assumed hydrogen price of € 1.99 per
kg. The CAPEX costs in this scenario is about € 1.4 million, consisting of about € 1 million for the
electrolyser, € 375,000 for the fuel cell, and the remainder for the small storage facility.
In scenario C, all the conditions of scenario B apply, except for the investment in a fuel cell. CAPEX
costs therefore are € 375,000 less, and it is of course no longer possible to sell electricity from the
platform.
In scenarios D and E the prime focus of the conversion/storage activities on the platform is on trying
to directly sell the hydrogen to the shipping sector (option 5) against a relatively attractive price.
However, this requires an investment in an offshore >300kg daily handling refuel station, for which the
investment costs are assumed to amount to € 2,530,000. Obviously, a fuel cell nor further storage
capacity on the platform is required. The high investment costs are offset by the relatively high
hydrogen price (€ 5.06/kg) assumed to be realised by selling it directly to mobility. The main difference
between scenarios D and E is that scenario D is not causing the fuel station to run at full capacity due
to a limited supply of hydrogen by the 1 MW electrolyser. This is why in scenario E the electrolyser
capacity is assumed to be 2 MW instead, so that the fuel station can operate more optimally. The
CAPEX investment of scenario D is just the electrolyser and the fuel station, in total just over € 3.5
million; in scenario E the CAPEX will be about € 1 million higher because now two 1 MW electrolysers
will be installed.
All scenarios have been assessed with the help of the model described in Annex 2, assuming a 20-year
lifetime. The merit order of the various scenarios can be derived from the table representing the results
as outlined in Table 2.
In this table, first the annual revenues are indicated for the various options, including the estimated
bonus based on postponement of decommissioning. Also the costs have been specified. Together, this
27
information generates the annual earnings before interest and tax (EBIT). Subsequently, the net
operating profit less adjusted taxes (NOPLAT) and free cash flows (FCFs) are given. Given the CAPEX
costs for the various scenarios, the NPV per scenario has been established. This leads to the following
merit order: the best option seems to be to use the platform for selling the hydrogen directly to the
shipping sector via an offshore refuelling station, while employing an electrolyser capacity sufficient to
make this station operate at sufficient capacity (scenario E). Obviously, this option assumes that
demand is sufficiently large to meet supply.
A next option in the merit order is to generate hydrogen and oxygen to be sold directly to the chemical
industry (scenario A). Obviously this scenario assumes that the grid allows for transporting the gases
onshore, or if dedicated transport systems would be used, the price received by the platform is
equivalent to a grid-connected case.
All other scenarios, either introducing a fuel cell for power-to-gas-to-power conversion, and/or trying
to directly sell the hydrogen through the gas grid to the general gas market, or with a non-optimal
hydrogen production/direct sales to shipping mix, show a negative NPV.
Obviously, a major caveat with respect to the results of all scenarios, and the negative-NPV scenarios
(B, C and D) in particular, is that net positive externalities have not been included in the calculus. This
is an important observation because it could well be that, if included, several of the options could still
be attractive from the overall economic welfare perspective. Also, possible additional costs as a result
of the extension of a platform’s lifetime, such as based on maintenance and daily operation, that would
otherwise not occur, have been disregarded in this study.
Table 2. NPV calculations of the five scenarios
Scenario
Time (year)
An.Rev. arbitrage
An.Rev. H² to chemical
sector
An.Rev. hydrogen infeed
An.Rev. to mobility fuel
An.Rev to gas infeed
An.Rev Oxygen
Green
Decommissioning
bonus
Storage costs
Operational costs
Water
Depreciation
EBIT
Taxes
NOPLAT
Depreciation
FCF’s
A
0
1-20
€0
B
0
1-20
€ 749
€ 106.402
€ 6.587
n/a
n/a
n/a
€ 68.050
€ 16.455
n/a
n/a
€ 23.618
€ 71.599
€ 71.599
€ 78.839
€ 49.524
€ 1.836
€ 49.524
€ 66.328
C
0
D
1-20
n/a
0
1-20
n/a
E
0
1-20
n/a
n/a
n/a
n/a
€ 363.731
n/a
€ 108.164
n/a
€ 727.461
n/a
€ 216.327
€ 71.599
€ 71.599
€ 71.599
€ 22.538
€ 63.329
€ 637
€ 63.329
€ -30.825
€ 22.538
€ 46.454
€ 676
€ 46.454
€ 4.959
€ 78.839
€ 163.389
€ 2.919
€ 159.090
€ 139.256
€ 157.677
€ 212.914
€ 5.837
€ 204.315
€ 434.644
€ 13.266
€ 53.063
€0
€ -30.825
€ 992
€ 3.967
€ 27.851
€ 111.405
€ 98.661
€ 335.983
€ 49.524
€ 102.587
€ 63.329
€ 32.504
€ 46.454
€ 50.421
€ 159.090
€ 270.495
€ 204.315
€ 540.298
€ 6.985
€ 17.450
n/a
n/a
€ 25.046
28
Investment cost
€ -1.100.540
€ -1.407.312
€ -1.032.312
NPV of FCF’s
€ 1.121.432
€ 355.316
€ 551.179
NPV of salvage value
NPV
IRR break-even
€ 30.652
€ 51.544
7,16%
€ 39.196
€ -1.012.800
n/a
€ 28.752
€ -452.382
n/a
3.8.
€ -3.535.335
€ 2.956.924
€ -4.540.335
€ 5.906.280
€98.466
€ -479.945
n/a
€ 126.457
€ 1.492.402
10.40%
Sensitivity analysis
The question arises how sensitive the NPV values generated above are for relatively small changes in
specific parameter values. In order to test this, for the two scenarios generating a positive NPV (A and
E), the following adjustments have been simulated. The other scenarios are assumed to remain out of
the scope of investors for the time being.
3.8.1. Sensitivity analysis: scenario A (selling to the chemical industry)






If one would succeed, with very minor additional costs, to raise the 5365 assumed running
hours of the electrolyser per year to 6000, the overall NPV would increase from about € 50,000
to about € 230,000.
If the costs of the electrolyser per MW would decline by a quarter (from € 1 million to
€ 750,000), this would lead, ceteris paribus, to a NPV of some € 370,000 (compared to the
about € 50,000 of the base case).
If we combine the above two assumptions, 6000 running hours and a quarter less expensive
electrolyser investment, the NPV raises from the € 50,000 mentioned to a level of about
€ 550,000.
If somehow either the conversion efficiency of the electrolyser (currently 210 Nm3/MWh)
and/or the price received from the chemical industry would increase, with a combined impact
of 10%, the NPV increases to some € 180,000.
If the 10% efficiency effect would materialise and also the 25% cost reduction of the
electrolyser, given the base case 5365 assumed running hours, then the NPV raises to about
€ 770,000.
In the most positive scenario, in which all three key variables develop in the positive direction
– running hours increasing from 5365 to 6000 hours, costs of the electrolyser a quarter down,
and efficiency effect +10% - the NPV raises to a level in the order of € 1 million. Note again,
that externalities are not included, so that from the welfare perspective returns can be even
more positive.
3.8.2. Sensitivity analysis: scenario E (direct selling to the shipping sector)



If the costs of the electrolyser comes down by a quarter, the NPV found for the base case,
about € 1.5 million, raises to a level of about € 2.1 million.
This scenario assumes an almost complete (23.3 hours per day) running time of the
electrolyser; the positive NPV disappears if, ceteris paribus, the number of daily running hours
gets less than about 19.
If the efficiency would increase by 10%, the expected NPV would increase from about € 1.5
million to a level of about € 2.7 million.
29
3.9.
The future case
Power-to-gas conversion by definition is something of the future. Even if a series of successful pilots
will be set up at relatively short notice, it is fair to assume that a commercial stage of large-scale powerto-gas conversion will only take off in the 2020s at the earliest. That is why, in the ideal case, the
assessment of the power-to-gas business case would use future data of the main input and output
parameters, such as electricity prices, ‘green’ premiums, hydrogen prices, investment costs, etc. In the
following, we have tried to make a rough approximation of future conditions by assuming that the
German electricity price data of 2006-2014 will apply to the overall NSA. The idea behind this
assumption is that the high share of renewables in the German gross electricity consumption
(increasing from 12% in 2006 to 28% in 2014 (Federal Ministry for Economic Affairs and Energy, 2015))
will, in the 2020s and thereafter, also apply across the NSA, and therefore also the related German
electricity prices and their volatility. For details, see the background report by Van Schot (2015).
In addition we assumed that in the future period a serious ‘green fiscal premium’ will apply across the
NSA, which is roughly equivalent to the current Netherlands SDE+ premium, or some 30% of the sales
price (Jansen, 2015). Also, we assumed that hydrogen directly sold to the mobility sector (either
shipping or trucks and other road vehicles) will benefit from an exemption of the excise duties, which
traditionally amount to about half of the sales price, and that this ‘premium’ can be captured by the
supplier of the green hydrogen (Jansen, 2015; Moes, 2015).
The assessment of the NPV as described above has been repeated below in order to mimic a powerto-gas business case under ‘future conditions’ (indicated by an ‘*’ to differentiate from the
corresponding base cases). In doing so, we concentrated on three options only: selling the hydrogen
and oxygen to the chemical industry (scenario A*); mixing the hydrogen with natural gas to be
distributed via the gas grid (scenario C*); and selling the hydrogen offshore directly to the shipping
industry (scenario E*, again assuming a 2MW electrolyser).
Table 3. NPV calculations of the future scenarios
Scenario
Time (year)
An.Rev. arbitrage
An.Rev. H² to chemical sector
An.Rev. hydrogen infeed
An.Rev. to mobility fuel
An. Rev to synthetic gas
An.Rev Oxygen
Green Decommissioning bonus
A*
0
1-20
€0
€ 309,266
n/a
n/a
€0
€ 106,602
€ 71,599
C*
0
1-20
€0
n/a
€ 104,659
n/a
€0
€66,739
€ 71,599
E*
0
1-20
€0
n/a
n/a
€2,408,227
€0
€ 221,320
€ 71,599
Storage costs
Operational costs
Water
Depreciation
EBIT
€ 78,839
€ 49,524
€ 2,703
€ 49,524
€246,356
0
€ 45,225
€1,801
€ 45,225
€ 150,746
€ 157,677
€ 212,914
€ 5,837
€ 204,315
€ 2,120,267
Taxes
NOPLAT
€ 49,271
€ 197,085
€30,149
€120,597
€ 520,067
€ 1,600,200
Depreciation
FCFs
€ 49,524
€ 246,609
€ 45,225
€165,822
€ 204,315
€ 1,804,515
Investment cost
NPV of FCFs
€ -1,100,540
€ 2,695,814
€ -1,005,000
€ 1,812,682
€ -4,540,335
€ 19,726,097
30
NPV of salvage value
NPV
IRR break-even
€ 30,652
€ 1,625,926
22.0%
€ 27,991
€ 835,673
15.6%
€ 126,457
€ 15,312,219
39.6%
The results clearly indicate that selling the hydrogen offshore to the shipping industry offers by far the
best return, and in fact an attractive IRR. Obviously, the exemption of excise duties is an important
determinant of this positive outcome; an additional scenario (not shown) assuming that such
exemption would not apply, provides a significantly less positive result, but still a NPV of some € 2
million and an IRR of some 12%. So, even then this option would provide the best alternative in terms
of NPV, but not in terms of IRR, because of the relatively high level of CAPEX of this option. Obviously
this scenario presupposes sufficient demand for green hydrogen at the offshore refuel station.
Selling the hydrogen to the chemical industry (assuming available transport capacities) also offers an
attractive return, and may be a somewhat more realistic option on the short to medium term given
that the hydrogen-to-chemical infeed is more developed than the hydrogen-to-mobility option; and
even mixing the hydrogen to the natural gas – an option that may be feasible already at short notice –
provides positive results.
4. Technical issues
4.1.
Introduction
The purpose of this chapter is to identify and clarify from an early stage, the main technical barriers
when considering installing a demonstration power-to-gas system on a disused or functioning oil and
gas offshore platform. Identifying these barriers at an early stage may help preventing many problems
later on. In particular, it helps in selecting which gas should be the system’s output (hydrogen or
methane). Moreover, it is of course vital to know which barriers are illusory and which have solutions.
4.2.
Offshore power-to-gas
considerations
demonstration
plant:
some
overall
In order to being able to identify the main possible technical bottlenecks for offshore energy
conversion projects, it is important to first outline the technical components and processes that may
relate to: an offshore power-to-gas plant; feed-in of hydrogen into the existing natural gas grid;
utilisation and management of heat; and electrolyser technology selected.
The possible components of an offshore power-to-gas system are: electrolysis, methanation, CCS,
desalination and water treatment, hydrogen, oxygen and CO2 storage, and gas purification.
The operation of the electrolysis is unsteady insofar as it follows the fluctuating input of renewable
power into the system. Chemical methanation instead has to be steadily operated with elevated
temperatures and pressures. Neither frequent start-up and shut-down cycles nor significant load
changes are possible. Specific sensitivity to load changes depends on the reactor concept, but basically
the load flexibility is limited. Hence an intermittent storage of hydrogen is necessary; the size of the
storage tank depends on both the fluctuations in electrolysis and the load flexibility of methanation
31
(Schaub, et al., 2014). The same considerations are basically also valid for CO2,, although the
intermittent storage of CO2 is usually simpler than that of hydrogen.
Due to the high critical temperature of 31°C, CO2 can be liquefied by compression. Whereas
conventional methanation processes and catalysts have been developed for carbon oxide as feed gas,
power-to-gas methanation utilizes CO2 as educt. The educt gases (hydrogen and CO2) have to be
compressed to the operational pressure of the methanation system. Electrolysis is already operated
with elevated pressures depending on the utilised technology. In contrast, CO2 sources are most
probably at atmospheric pressure, and thus need compression in case of chemical methanation.
Means to improve the economic viability of the methanation process should be considered. The cost
effectiveness of methanation can be positively influenced in the following ways:




by reducing the effort required for gas upgrade downstream from the reactor;
by utilizing the released reaction heat within the power-to-gas process chain and outside the
system, respectively (this will be discussed in more detail in section 3.4);
by increasing the lifetime of the catalysts; and
by achieving high annual operational hours.
The product-gas upgrade aims to meet the relevant regulations for injection of SNG or biogas into the
gas grid. Multi-stage methanation reactors enable high methane yields and thus result ideally in a
simple water condensation unit as the means of product gas upgrade. Other potential upgrade systems
are based on membranes or pressure swing adsorption. Depending on the entry point to the gas grid,
a pressure adjustment between the methanation unit and local grid pressure is required.
Plant size, reactor design, set-up of the process chain and annual operating hours of an electrolysis and
methanation unit within a power-to-gas system substantially depend on the specific local conditions:
available space and allowable weight that can be added to the platform, available quantity and
temporal profile of renewable power and thus hydrogen production, CO2 sources as well as size,
pressure level and load flow of the natural gas grid. Therefore, each electrolyser and methanation unit
of a power-to-gas process chain has to be tailored to the specific boundary conditions for each
platform. Since no platform has been selected yet, and since the size of the demonstration plant greatly
depends on the specific boundary condition of each platform, at this stage of the project we cannot
provide further detail about the specifications for the demonstration plant, such as size.
4.2.1. Integration of hydrogen into the natural gas grid
The products of the chemical conversion in a power-to-gas plant—hydrogen and SNG (methane)—
have to be preferentially transported by the natural gas grid and stored in the grid as well as in the
connected large-scale storage facilities. Hence, the impacts of the injection into the grid of hydrogen
or SNG have to be evaluated. Furthermore, the requirements for the injected gas composition and gas
volume, as well as any restrictions for the product gas injection have to be considered.
The case of SNG as end product of the power-to-gas process chain is less critical than that of hydrogen,
because natural gas consists to a large extent of methane. Accordingly, a practically unlimited injection
of SNG into the gas grid is possible. Since methanation is an equilibrium reaction, parts of the educt
gases, hydrogen and CO2, are not converted to methane. Furthermore, the product-gas mixture
emerging from the methanation reactor contains significant amounts of steam, the main byproduct of
32
the methanation reaction. Accordingly, a product-gas upgrade is necessary in order to meet the
requirements for injection of the produced SNG into the gas grid. The injection of hydrogen into the
natural gas grid raises a number of questions that have been investigated in some recent studies
(Müller-Syring, et al., 2012; 2013; Florisson, 2010; Müller-Syring & Henel, 2014).
The main advantage of using the natural gas grid is that no additional pipeline is required to transport
hydrogen. The disadvantage is that the production of hydrogen is limited to the admixing percentage
and is completely dependent on the flow of natural gas in the pipelines.
4.2.2. Heat management
As previously mentioned, utilisation of the generated heat will increase both the efficiency of the
system and the economic viability of the methanation process, and hence the economic viability of the
whole power-to-gas. The aim of heat integration in general is to couple the released heat from the
methanation reaction with the required thermal energy for the CO2 capture process. Thus the
economy of the system can be improved by energy savings in the CO2 separation and by decreasing
the cooling demand of the methanation reactor. The possibility of heat integration between
methanation and carbon capture processes has been simulated by Fraubaum and Haider (2014) with
ASPEN. An example of power-to-gas was simulated in this study and two different methanation
processes were elaborated.
Depending on which methanation process is used, the released heat from the reactors can be used to
produce superheated steam or high-pressurized saturated steam. In both cases, the steam produced
had a significantly higher energy level than that required for the CO2 desorption (2 bars, 120.3°C). This
means that the heat produced can be utilised in another process. In the onshore power-to-gas system,
the steam can be expanded in a condensing turbine. Since possible carbon sources originate from
industrial processes, like fossil power plants and steel plants, steam-power plants already exist, and
therefore only steam turbines need to be adapted.
In our case, the heat generated from the methanation process can be utilised in several ways. If the
CCS process is happening offshore, as in the case of natural-gas sweetening, the released heat can be
used for the process. The additional heat can then be used to reduce the high energy requirements of
the water desalination plants, to reduce heat demand for the gas processes available at the platform,
or as in the onshore case, it can be expanded in a condensing turbine if a steam-power plant already
exists at the platform.
4.2.3. Electrolyser selection
Water electrolysis plays a central role in power-to-gas systems as it represents the linkage between
electrical and chemical energy, independent if the produced hydrogen is used in its elemental form or
as an intermediate for further chemical reactions. The most important requirements on electrolysers
for power-to-gas systems are highly dynamic modes of operation, wide partial load ranges with
sufficiently high efficiencies and satisfying gas purity levels, compact stack designs, high unit-power
densities, high production capacities, and low- investment operating costs. Although water electrolysis
is already a well-established technology, further improvements are required to meet these
requirements. Currently, a lot of fundamental and applied research and development efforts are
33
underway to pave the way for a broader implementation of electrolytic hydrogen production into the
market and to facilitate a larger integration of the power-to-gas technology into the electrical grid.
There are two main commercialised water electrolysis technologies now available: alkaline electrolysis
(AEC) and polymer electrolyte membrane electrolysis (PEM). Each is at a different level of
development. The main technical differences between these two technologies are the operating
temperature, the operating current density and voltage, the class of materials used for catalysis, the
pH value, the type of the electrolyte used, and thus the configuration of the particular electrolyser
system. An overview of the important parameters of the two main water electrolysis technologies is
given in Table 4. For each parameter, typical values are presented.
Table 4: Important parameters of the main water electrolysis technologies
Alkaline low-temperature electrolysis technology is the oldest, currently most mature and cheapest
technology available. In large-scale electrolytic hydrogen production plants, exclusively alkaline
electrolysers are being used so far. However, low current densities and rather limited modes of
dynamic operation are currently major limitations of that technology. To make the AEC technology
more compatible with power-to-gas applications, further developments are essential.
Acidic solid polymer electrolyte (PEM) technology has made significant progress over the past decade
and is on its way to leave niche applications. Due to various unique advantages over alkaline systems
like the compact system design, high current densities, high operating pressures, high flexibility with
respect to modes of operation, and wide partial load ranges, PEM technology offers a great potential
to become a serious competitor to alkaline electrolysis systems for many types of applications. Due to
these advantages, PEM technology is probably the most compatible technology for power-to-gas
applications at present. The most limiting disadvantages of that technology are its high costs, limited
resources, and the lack of adequate scale up procedures.
4.3.
Barriers
This section addresses the major barriers to the implementation of a demonstration power-to-gas
plant aboard an offshore platform in the challenging environment of the North Sea. First, we will deal
with the problems of distant and fluctuating electricity supply to an offshore power-to-gas facility.
Second, we provide a review of the oil and gas industry’s techniques of risk assessment and
management. On this basis the third subsection addresses the specific and critical issue of corrosion
34
risk and its management via the selection of appropriate materials and the integration of inherent
safety early in the design phase. Next, options for the sourcing of CO2 for the plant are considered,
including two relevant projects currently in operation. Finally, issues of actual installation are
considered, including CO2 sourcing, questions of plant weight and volume and platform structure, and
issues with the available electrolytic technologies.
4.3.1. Source of electricity for the demonstration plant
In actual practice, it is well possible that the nearest wind farm is several dozens of kilometres away
from the platform. For large-scale power-to-gas connections, this may not pose a problem, but for a
small-scale pilot plant, it could be economically infeasible to install several kilometres of cables. In that
case another electricity source should be found. That could be the electricity produced by existing
generators on the platform.
Because usually the required power at a platform ranges from a few to hundreds of megawatts,
platforms are typically fitted with heavy power generation equipment designed to ensure sufficient
capacity. The power arrangement typically consists of four gas turbine units, one used at full capacity
and the remaining three throttled to meet varying demand or otherwise reserved for redundancy. This
high capacity is necessary to meet the high availability requirements of each independent platform.
However, operating gas turbines at low efficiency results in high fuel consumption and elevated
emissions. So, it will often be feasible to supply electricity to the power-to-gas system from these
generators. Whenever one turbine is operating at a level below its rated power, the power-to-gas
system will be ‘plugged in’. The amount of electricity consumed by the power-to-gas system will be
selected so that this turbine will be working at its highest efficiency. In this way the power generation
system will be working at its highest efficiency and hydrogen or methane will be produced from the
otherwise unused electricity.
The amount of electricity consumed at the platform – and thus the functioning of the generators –
depends on many variables such as the gas treatment process, fluctuating gas demand, and weather.
Hence, the actual working of the power-to-gas system connected to the generators will be fluctuating,
much as if it was connected to a wind source. When the electricity source is found not to be following
the wind source, one has the option to turn it on and off according to the wind profiles.
4.3.2. Material selection, corrosion risk assessment, and corrosion management
When considering installing a power-to-gas system offshore, a major concern is the corrosion level. At
sea, corrosion is much more rapid and severe than inland. This has to be taken into consideration at
an early stage of the design phase.
Materials selection should be optimized and should provide acceptable safety and reliability. As a
minimum, the following should be considered:



Corrosivity, taking into account specified operating conditions including start up and shutdown conditions;
Design life and system availability requirements;
Failure probabilities, failure modes, and failure consequences for human health, environment,
safety and material assets;
35







Resistance to brittle fracture;
Inspection and corrosion monitoring;
Access and philosophy for maintenance and repair;
Minimum and maximum operating temperature;
Minimum and maximum design temperature;
Weldability (girth welds and overlay welds);
Hardenability (carbon and low alloy steels).
For the final material selection, the following additional factors should be included in the evaluation:




Priority should be given to materials with good market availability and documented fabrication
and service performance.
The number of different materials should be minimized considering stock, costs,
interchangeability, and availability of relevant spare parts.
Environmental impact assessment and authority permissions, e.g., on discharge of chemicals
like corrosion, must be obtained.
Inhibitors should be considered.
In addition, a corrosion management programme should be prepared and implemented before the
start-up of production. A general corrosion management system has been outlined that provides a
progressive framework compatible with the requirements of an offshore safety management system
aimed at securing the integrity of topside processing equipment. The safety management system
comprises effective plans and organisations to control, monitor, and review preventative and
protective measures to secure the health and safety of employees. A structured approach is for
instance based on Total Quality Management (TQM) schemes (Oakland, 1995), used to control risks
within organisations.
Practical experience from the NSA has shown that the development of comprehensive corrosion
management systems, coupled with a commitment by the operator, the maintenance contractor, and
specialists, sub-contractors, and consultants, can lead to a major improvement in the operation of
offshore topside process facilities.
4.3.3. CO2 source offshore
If the power-to-gas unit is complemented by a methanation unit, the availability of CO2 can be a major
barrier. In the case where CO2 is needed offshore, two options arise to deliver a reliable constant
source of CO2. The first option is for CO2 to be captured onshore and transported to the platform. Part
of it will be used for the methanation process and the rest may be stored in geological storage mediums
or used for enhanced oil recovery. The second option is for CO2 to be captured offshore from direct
purification of the extracted natural gas.
CO2 is a naturally occurring diluent in oil and gas reservoirs, and it can react with H2S and H2O to form
corrosive compounds that threaten steel pipelines. It is therefore critical that pipeline levels of CO2 are
no more that 2%-3%. Well-head natural gas can contain as much as 30% CO2. Removal of CO2 from
natural gas utilises membrane technologies or larger amine plants.
While accurate figures are published for annual worldwide natural gas production (BP, 2004), none
seem to be published on how much of that gas contains CO2 . Nevertheless, a reasonable assumption
36
is that about half of raw natural-gas production contains CO2 at concentrations averaging at least 4%
by volume. These figures can be used to illustrate the scale of this CO2 capture and storage opportunity.
If half the worldwide production of 2618.5 billion m3 of natural gas in 2003 is reduced in CO2 content
from 4 to 2 mol%, the resultant amount of CO2 removed would be at least 50 Mt CO2 per year.
Currently, there are three operating natural gas plants in the world that are designed to capture and
store CO2: a Statoil plant at Sleipner in the North Sea, the K12B project in the Dutch North Sea still
under development, and the BP-Sontrach-Statoil In Salah plant in Algeria. Both the Sleipner and the In
Salah facilities are capable of capturing about 1 Mt CO2 /yr. Those projects could be interesting CO2
sources for a possible NSA power-to-gas/methanation demonstration project.
To illustrate, it may be worthwhile to zoom in on the K12-B gas field, which is located in the Dutch
sector of the NSA, some 150 km northwest of Amsterdam. The natural gas produced has a relatively
high CO2 content (13%) and the CO2 is separated from the production stream prior to gas transport to
shore. The CO2 is injected into the field above the gas-water contact at a depth of approximately 4000
m. K12-B is the first site in the world where CO2 is injected into the same reservoir from which it
originated. CO2 injection began in May 2004. At the same time, extensive measurement programs have
been undertaken. These programs are dedicated to determining the potential for both CO2 storage and
enhanced gas recovery (EGR). As of March 2015, CO2 injection continues, and since 2004 a total of 90
kt of CO2 has been injected in the nearly depleted gas field K12-B (TNO, 2007).
4.3.4. Weight and volume analysis
Weight and volume analysis is an important factor to consider when exploring the possibility of
installing a power-to-gas system on existing oil and gas platforms. This barrier depends very much on
the size of the power-to-gas plant and on the chosen platform, since platforms come in different types
and sizes depending on the purpose of the platform and the depth of the sea where they are located.
The demonstration plant will be relatively small. However, it will still constitute an extra load and
require extra space on the platform. Once the size of the power-to-gas plant is determined, a weight
and volume analysis should be done to check if the platform’s structure and volume can accommodate
the additional system. If not, some redundant equipment can be decommissioned, structural
reinforcement can be done, or an addition to the platform can be installed.
Oil and gas platforms are carefully designed to achieve weight and space saving while incorporating all
the necessary process and utility equipment, including a drilling rig, injection compressors, gas turbine
generators, accommodation for operating personnel, piping, a crane, a helipad, and oil and gas
storage. For this reason it is very difficult to install a new system without sacrificing another system
already installed.
Although the design of offshore structures is dominated by environmental loads, especially wave load
(El-Reedy, 2012), the extra weight added by the power-to-gas system should be analysed. The platform
should be able to accommodate the following additional equipment, that could include an AC-DC
converter, the electrolyser, a methanation unit, a water treatment station, a post-treatment station
for gases, gas storage facilities, and all the related piping, instrumentation, and firefighting equipment.
In the case of large-scale implementation of power-to-gas, the gas storage and the electrical hub
together add the biggest weight to the platform. An illustrative example of the potential weight is
37
‘Borwin2’, an 800MW transformer station located about 100 km northwest of the North Sea island of
Borkum in Germany. This HVDC platform weighs about 12,000 tonnes, and has a length of 72 m and a
width of 51 m (Siemens, 2015). Given that the size of a typical platform in the North Sea is around 70
x 80 m, a detailed weight-and-volume analysis should be done.
As an important input to electrolysis, pure water is needed for the production of hydrogen. In order to
get pure water, a desalination and water treatment plant is needed. Depending on the size of the
treatment plant, this process might be considered a barrier since it requires a large space on deck and
require a lot of energy.
In the case where the volume is not enough, a neighbouring platform could be used, since the
platforms are usually installed in clusters with several kilometres between each platform. One platform
could be used for the P2G process and the other as a HVDC platform.
4.3.5. Installation of the system offshore
The fact that the system has to be transported to an offshore site should be addressed in the design
phase. Specifically, the system should be modular and compact to facilitate transportation and reduce
installation time offshore.
4.3.6. Technology statuses and challenges for water electrolysers
Independent of the particular technology, the current major drawbacks of currently available water
electrolysis systems are limited capacity, suboptimal degradation behaviours, and high front-end
investment and operating costs. Substantial R&D efforts are still needed for each of the water
electrolysis technologies to overcome those problems and to pave the way for a broader introduction
of electrolytic hydrogen production into the market.
4.3.6.1. Technology status and challenges for alkaline water electrolysers
With respect to system durability of alkaline water electrolysers, typical degradation rates of 1–3 μV/h
are offering tens of thousands of hours of operation and a regular general overhaul every ~10 years.
This satisfies industrial requirements already quite well. All this holds for conventional, industrial
applications under broadly constant operating conditions and fairly constant H2 production levels. In
the course of power-to-gas applications, electrolysers are coupled to renewable sources of electricity,
which mostly supply intermittent power. Up to now, this dynamic operation commonly results in lower
gas quality, lower system efficiency, more frequent system shut-downs and generally reduced system
durability. The system's ability to follow rapid load variations is not limited by the kinetics of
participating electrochemical reactions but rather by the inertia of auxiliary system components.
Recent reports show that advanced alkaline systems, which are specially designed for intermittent
power applications, are able to provide an extended dynamic range of ~10–100% of rated capacity and
improved response times in the few-seconds range. Relatively long cold start times, the necessity of
holding currents during stand-by, and gas purity problems during partial load periods are still some of
the most critical issues for intermittent operation of alkaline electrolysers. However, the implications
for operational lifetime of such intermittent operation remain mostly unknown, and elucidation of
those complex problems is the subject of various current research projects. In addition, these
38
advanced systems are only available on a small scale and, like other electrolysis technologies, need to
be scaled up.
The specific investment costs for alkaline systems in €/kWel predominantly depends on the system
size and the operating pressure. Pressurised systems are roughly estimated to be 20–30% more
expensive than atmospheric systems over a wide range of system sizes. Raising the capacity of
electrolysis systems from the kWel to MWel+ range results in a reduction of investment costs by a
factor of ~2.5–3. This yields a rough estimate of specific investment costs of around € 1,000–1,300 per
kWel on average. The electrolysis stack generally accounts for 50–60% of the total system costs. This
is true for basic system configurations. However, upgrading the system with components like (for
example) enhanced purification systems, compressors, more efficient AC/DC converters, and so forth
can easily add additional 25–50 % to the basic costs. For alkaline technology it is generally estimated
that cost reductions in the future will be mainly driven by economies of scale rather than by the further
development of particular components.
4.3.6.2. Technology status and challenges for PEM electrolysers
PEM technology is generally less mature than AEC technology and up to now has been used exclusively
for small-scale applications. However, this technology has received a great deal of attention in the past
decade. This is mainly because of its key advantages like high cell efficiencies, high current densities at
low corresponding cell voltages, and hence high power densities and the ability to provide highly
compressed hydrogen. Furthermore, PEM technology allows a highly flexible mode of operation
enabled by very fast shut-down and start-up times, very fast load following, and a partial load range of
5–100%. Those advantages perfectly match many of the basic requirements of power-to-gas
applications, being directly coupled to fluctuating renewables, and being connected to high-pressure
hydrogen storage units.
The main weak points of the PEM technology are the difficult upscaling procedures due to system
complexity, limited global availability of PGMs for catalysis, and expensive component materials, which
together lead to rather high specific system costs. In the past, low system durability has also often
been noted as a disadvantage. Recently, however, significantly improved degradation rates in the
range of 10 μV/h or lower have been announced by various manufacturers. This shows that efforts to
solve stability problems are on the way to catching up with AEC technology. In spite of the difficulties
of upscaling, system size has increased significantly during recent years. Major PEM manufacturers
announced in 2013 that they are working on stacks in the several-100s kW to even MW range, to be
launched in the next few years.
5. Possible further steps
Given the potential in the NSA to create smart sustainable combinations, such as based on converting
offshore wind energy into gases by using existing O&G platform and grid infrastructures, it is important
to try to develop first steps, but also to keep the longer-term fuller NSA smart sustainable combinations
perspective into the picture. The current report can only be seen as a small first step, i.e. a prefeasibility study on a possible first conversion pilot, but also as a first step towards a plan for a much
wider application of P2G in the North Sea area.
39
A wider green offshore plan in fact sets the overall stage of this study and could - depending on further
progress, the information gathered, new technological, economic and policy developments – have the
following general outline/timing:





Pre-feasibility study smart sustainable combinations pilot:
Feasibility study smart sustainable combinations pilot:
Start of the pilot:
Start envisaged demonstration project:
Further extension and wider application of power-to-gas in the NSA:
2015
2016
2017
2020
Starting 2020
It would seem desirable that, parallel to the envisaged pilot and demonstration projects, an official
NSA smart sustainable combinations power-to-gas master plan would be designed to set the stage for
the post-2020 deployment of prospective offshore conversion technologies enhancing the efficiency
and effectiveness of the overall NSA energy system.
In preparing a pilot phase feasibility study, next to the analyses presented above, also an inventory has
been made in the spirit of this study of the potential locations and capacities of offshore NSA
conversion activity. In doing so, we have limited ourselves to the DCS (with about 160 platforms and
some 275 pipelines with a combined length of about 3,900 km), acknowledging that similar inventories
for the other NSA countries’ continental shelves would be needed as well.
In the DCS, seven designated wind energy areas are appointed: Holland Coast Areas 1, 2 and 3, North
Netherlands Coast (north of the West Frisian islands), ‘IJmuiden Ver’, and Future Wind Energy Areas A
and B. If we limit ourselves to those areas, and the area within a distance of max. 10/20 km, then the
number of platforms available for conversion would be as reflected in Table 5. For a detailed
illustration of the underlying data and analysis of Table 5, see the background report by Schulze and
Florisson (2015). Assuming a max. 20-30 MW electrolyser capacity per platform, the estimated
conversion capacity – if all neighbouring platforms would be used for conversion – is also presented in
Table 5. Given the expected wind capacity of the medium-term appointed wind energy areas (non‘Future’) of about 3000 MW, the neighbouring (< 10 km) conversion capacity of about 400 – 600 MW
would be capable of converting about a sixth of the generated wind energy; if the area is expanded to
< 20 km, the conversion capacity grows to about 580 – 870 MW, or about a quarter of the generated
wind energy. Obviously, if also platforms somewhat further away from the wind areas would be
connected, this figure may increase substantially.
Table 5. Available platforms per designated offshore wind energy area on the DCS
Designated wind energy area
Expected
installed wind
farm capacity
(MW)
Holland Coast Area 1
North Netherlands Coast
Ijmuiden Ver
Future Wind Energy Area A
Future Wind Energy Area B
~350 MW
~350 MW
~300 MW
~700 MW
~1400 MW
Not known
Not known
Number of
nearby (10
km / 20 km)
platforms
7/9
4/4
6/8
2/3
1/5
15 / 15
4/4
Estimated
conversion
capacity
(10 km) in
MW
140 – 210
80 – 120
120 – 180
40 – 60
20 – 30
300 – 450
80 – 120
Estimated
conversion
capacity
(20 km) in
MW
180 – 270
80 – 120
160 – 240
60 – 90
100 – 150
300 – 450
80 – 120
40
The estimated installed capacity of electrolysers per platform of 20-30 MW would result in a
production rate of 1-1.4 Nm³/s of hydrogen or 0.2-0.25 Nm³/s of SNG. This amount of gas can be easily
accommodated in the pipelines connected to the production platforms, as it presents only a small
fraction of what is usually produced from gas and oil wells. By means of the pipelines, the hydrogen or
SNG can be transported ashore.
This is not to say, however, that hydrogen transport via existing natural gas pipelines, even in small
concentrations, is without difficulties. Examples of issues that will need to be resolved are related to
compression rates, pipeline materials, and hydrogen admixing technology.
6. Conclusion
So far, no offshore power-to-gas activity has been initiated, to our knowledge, in the North Sea Area.
The rapid expansion of offshore wind capacity, however, raises the issue how the future energy system
will behave in a world with much more intermittent renewable sources. A specific issue of growing
importance is if intermittent energy from wind can somehow be stored to better suit the time profiles
of demand.
Power-to-gas converts wind energy into a storable gaseous form, and therefore may provide a storage
facility needed to optimise the overall energy system. Real-life experiments will tell us if offshore
conversion and possibly storage of gases converted from wind energy may at some stage become
economically feasible. Such experiments may also teach us how the offshore application may differ
from onshore applications.
This pre-feasibility study addresses the issue of the economic, commercial, and technological feasibility
of a number of offshore conversion options that all have in common that wind energy through
electrolysis is turned into a gaseous form, to be sold to destination markets whether or not after some
further conversion. We considered five options, and found that a positive business case applies
typically if the hydrogen and oxygen generated offshore can be sold at dedicated niche markets, that
appreciate the gases delivered to be ‘green’ (unlike traditional hydrogen and oxygen offered on the
market). Such destination markets could be the chemical industry or the mobility sector. In fact, we
also found a positive NPV if the hydrogen is admixed to the ongoing natural gas delivery system
assuming grid availability; the positive NPV was in such cases, however, fairly limited. The theoretically
best model in terms of NPV would be the case in which the green hydrogen produced at platforms to
be decommissioned would directly be sold as a fuel to the shipping industry via fuelling facilities on
the spot. This option, which for the moment is still theoretical because hydrogen-fuelled vessels are
still extremely rare, could be a perspective for the future.
A feasible situation could in fact be that platforms that are out of production or close to that, will be
used for electrolysis, generating oxygen and hydrogen, that then is used for a mix of destinations:
direct sales of hydrogen to the industry and possibly the shipping sector while admixing possible
surpluses occasionally to the natural gas system.
41
The main technical barriers of offshore conversion have to do with safety issues, space availability on
the platforms, and corrosion. Also connecting the offshore wind farms via power cables with the
platforms may be complex.
On the whole, the NPV values for the various options mentioned turned out to be surprisingly more
positive than anticipated, while also the technical barriers seemed to be not insurmountable. This was
the more surprising, since in the study the externalities – on average expected to be positive due to
the savings on power grid investment and on postponing decommissioning – have not been included
in the economic analysis. The NPV outcomes of the options became even more positive in the scenarios
in which the assumptions were made: that power prices will become more volatile as the scale of
intermittent supply continues to increase; and that the ‘green’ character of the gases will in the future
induce a premium price as compared to fossil gases.
Annex 1: Conversion model used for the energy
conversion process
Basically, a number of conversion factors need to be established: from wind to power, from power to
hydrogen and oxygen, and possibly from oxygen to methane.
The model assumes the parameter values of a Siemens SWT-6.0-154 Turbine with the following
specifications (Siemens, 2013):





Nominal Power: 6 MW
Swept Area: SA = 18600 m2
Cut-in Wind speed: 3-5 m/s
Cut-Out Wind speed: 25 m/s
Average Power Factor: 𝐶𝑝 = 0.47
With respect to wind speed data it was not possible, in the absence of the information about the
platform location, to use offshore wind data. Therefore, instead, onshore wind data have been used
from ECN’s ‘Meteomast’ system.
The power converted from the wind into rotational energy in the turbine is calculated using:
1
𝑃𝑤 = 𝑁 × × 𝜌 × 𝑆𝐴 × 𝑣 3 × 𝐶𝑝
2
With






𝑃𝑤 : wind power (hourly production)
𝑁: number of wind turbines
𝜌: 1.23 𝐾𝑔/ 𝑚3
𝑆𝐴 : swept area = 18,600 m2
𝑣 : hourly average wind speed
𝐶𝑝 : average power factor = 0.47
42
Following the calculation of the hourly-generated wind power, the wind farm wake losses and AC/DC
transformation losses are applied, which leads to:
𝑃𝐹 = 𝑃𝑤 × 𝜂𝑤𝑎𝑘𝑒 × 𝜂𝐴𝐶/𝐷𝐶
The following losses were considered (Schepers, 2014):



𝑃𝐹 : final wind power
ηwake = 0.95
ηAC/DC = 0.95
The produced hydrogen can be calculated using the following formula:
𝑚(𝐻2 ) =
ηelectrolyser × Pallocated × density𝐻
× Utilization Rate
HHV
With


𝑚(𝐻2 ): mass of hydrogen in kg (idem for other gases)
ηelectrolyser = 0.7 (for the whole power-to-hydrogen process)




Pallocated : capacity of the electrolyser
HHV = 3.54 kWh/Nm3
density𝐻 = 0.0892 kg/Nm3
Utilization Rate = 0.91 (given the offshore factor, more time is needed for maintenance)
The mass of hydrogen produced depends on the number of running hours per year and the capacity
of the electrolyser. These two parameters can be changed to balance the hydrogen production with
the demand. The necessary storage is calculated at this stage.
From the methanation process equation (number) the molar stoichiometric ratio between CO2 and H2
is found to be 1:4. This determines the amount of hydrogen and CO2 needed for the system, and can
be calculated as:
for 𝑚(𝐻2 ) = 1𝑘𝑔
𝑚(𝐶𝑂2) =
1 𝑚(𝐻2 )
×
× 𝑀(𝐻2 ) = 5.5𝑘𝑔
4 𝑀(𝐻2 )
𝑚(𝐶𝑂2) = 5.5 × 𝑚(𝐻2 )
𝑀(𝐻2 ) =

2𝑔
𝑎𝑛𝑑 𝑀(𝐶𝑂2 ) = 44𝑔/𝑚𝑜𝑙
𝑚𝑜𝑙
𝑀(𝐻2 ): molar mass of hydrogen in g/mol (idem for other gases)
The above equations show that the amount of CO2 required by the process equals 5.5 kg per 1 kg of
hydrogen. The methane production per 1 kg of hydrogen can now be calculated:
for 𝑚(𝐻2 ) = 1𝑘𝑔
43
𝑚(𝐶𝐻4 ) =
1 𝑚(𝐻2 )
×
× 𝑀(𝐶𝐻4 ) = 2𝑘𝑔
4 𝑀(𝐻2 )
𝑚(𝐶𝐻4 ) = 2 × 𝑚(𝐻2 )
with 𝑀(𝐻2 ) = 2𝑔/𝑚𝑜𝑙 𝑎𝑛𝑑 𝑀(𝐶𝐻4 ) = 16𝑔/𝑚𝑜𝑙
The above equation shows that the ideal Sabatier process produces 2 kg of methane from 1 kg of
hydrogen. However, due to several losses during the process (mainly heat losses) the actual efficiency
of the process is between 70-85% (Grond, et al., 2013). In this study we will consider an efficiency of
80%.
Taking the efficiency losses into consideration, the actual methane production is:
𝑄(𝐶𝐻4 ) = 𝜂𝑎𝑐𝑡𝑢𝑎𝑙 × 2 × 𝑚(𝐻2 ) = 1.6 × 𝑚(𝐻2 )


𝑄(𝐶𝐻4 ): volume of methane produced
𝜂𝑎𝑐𝑡𝑢𝑎𝑙 : actual efficiency of Sabatier process = 0.8
Similar to hydrogen, the production of methane also depends on the capacity of the electrolyser and
of the methanation process and the number of running hours. Once the volume of the produced
methane is calculated for a typical scenario it can be balanced with the different demand patterns for
methane.
Annex 2: NPV model used for economic analysis and
related data for the Netherlands’ situation
Methodology
In this report, the economics of different power-to-gas options is basically assessed by net-presentvalue (NPV) analysis. NPV is a discounted cash-flow method that calculates the expected net monetary
gain or loss from a project by discounting all future cash inflows and outflows to the present point in
time using a specified rate of return. In this analysis the focus is on daily optimisation. It is based on a
stochastic calculus because one of the key inputs, prevailing electricity prices, tends to follow a
stochastic price pattern, induced by factors such as weather and technological developments (Veijer,
2014). The underlying model used for the NPV consists of two parts: the purchase of electricity to
produce hydrogen, and the market for the produced hydrogen.
𝐹𝐶𝐹
The NPV is given by: 𝑁𝑃𝑉 = ∑𝑇𝑡=1 (1+𝑟)𝑡 𝑡 − 𝐼, where 𝐼 denotes the investment costs; 𝑇 is the lifetime in
years; 𝑟 is the risk adjusted discount rate; and 𝐹𝐶𝐹 denotes the free cash flows. The NPV analysis is
quite sensible to the chosen rate of return, usually the weighted cost of capital, i.e. the average of
relevant equity and debt costs of capital, weighted by the fractions of their value. The internal rate of
return (IRR) depicts the discount rate at which the present value of inflows equals the expected
outflows of the project, and therefore, the rate of return at which the project breaks even. The NPV
decision rule usually implies that as long as it is positive, the investment decision will be positive as
44
well. In case of net positive externalities, such as usually in pilot projects, the NPV does not necessarily
need to be positive for a positive investment decision.
The free cash flows (FCF) are determined for each option by the following equations:
General model: hydrogen production
365 24
𝐹𝐶𝐹𝑡 = [∑ ∑(𝐾ℎ 𝑄ℎ ∗ ( 𝑃ℎ − 𝑃𝑒 ∗ 𝑞1 ) + 𝑄ℎ ∗ 𝑃0 ) − 𝐶 − 𝐷 − 𝑊 − 𝑆ℎ + 𝐺𝐷 ] ∗ (1 − 𝜏) + 𝐷
1
1
Where 𝐾ℎ is the power capacity in MWh, 𝑄ℎ is the quantity of hydrogen produced, which denotes one
if 𝑃𝑒 ∗ 𝑞1 <𝑃ℎ and denotes zero in all other cases, 𝑃ℎ denotes the selling price of hydrogen in €/kg which
is dependent on the hydrogen market, 𝑃𝑒 is the selling price of peak load electricity in €/MWh, 𝑞1 is the
conversion factor of electricity to hydrogen, 𝑃𝑜 denotes the selling price of oxygen in €/kg, C denotes
the annual fixed operation and maintenance cost, D denotes annual depreciation, W the cost related
to water consumption, GD the yearly Green Decommissioning bonus, S the yearly storage cost and 𝜏
denotes the corporate tax rate.
Moreover, for the different options 𝑃ℎ , D and S may take different values. For instance, the application
of hydrogen to the gas grid goes hand in hand with lower cost for storages, etc.
Additional FCF calculations are required for option 1 (hydrogen-to-power) and 6 (hydrogen to SNG).
The economic value of these options are determined by the following two equations.
365 24
𝐹𝐶𝐹𝑡 = [∑ ∑(𝐾𝑓 ∗ 𝑄𝑒 ∗ ( 𝑃𝑒 − (𝑃ℎ ∗ 𝑞12 ))) − 𝐶𝑓 − 𝐷𝑓 ] ∗ (1 − 𝜏) + 𝐷𝑓
1
1
Where 𝐾𝑓 denotes the total fuel cell capacity in €/MWh, 𝑄𝑒 the total quantity of electricity generated,
which takes the value one if 𝑃𝑒 > 𝑃ℎ ∗ 𝑞12 and 0 otherwise, 𝑃ℎ the selling price of hydrogen in €/kg
which is dependent on the hydrogen market, 𝑃𝑒 the selling price of peak load electricity in €/MWh, 𝑞12
the round trip efficiency of the electrolyser and fuel cell technology, 𝐶𝑓 the annual fixed operation and
maintenance cost of the fuel cell, 𝐷𝑓 annual depreciation of the fuel cell, and 𝜏 the corporate tax rate.
Option 6: Hydrogen-to-SNG
365 24
𝐹𝐶𝐹𝑡 = [∑ ∑(𝐾𝑚 ∗ 𝑄𝑚 ∗ ( 𝑃𝑚 − (𝑃ℎ ∗ 𝑞13 ))) − 𝐶𝑚 − 𝐷𝑚 ] ∗ (1 − 𝜏) + 𝐷𝑚
1
1
Where 𝐾𝑚 is the power capacity in MWh of the methaniser, 𝑄𝑚 the quantity of methane produced
which denotes one if 𝑃𝑚 > 𝑃ℎ ∗ 𝑞13 and zero in all other cases, 𝑃ℎ denotes the selling price of hydrogen
in €/kg which is dependent on the hydrogen market, 𝑃𝑚 the selling price of methane in €/kg, 𝑞13 the
conversion factor of hydrogen to methane, 𝐶𝑚 the annual fixed operation and maintenance cost of
the chemical methaniser, 𝐷𝑚 the annual depreciation of the chemical methaniser, and 𝜏 the corporate
tax rate. An overview of all parameters and their values is provided in Table 6.
45
Table 6. Parameters and values
Parameters
Parameters
𝐾ℎ
1MWh
𝑃ℎ,𝑐
60.40 per MWh
𝐾𝑓
375 KWh
𝑃ℎ.𝑔
37.48 per MWh
𝐾𝑚
375 KWh
𝑃ℎ.𝑚
95.53 per MWh
𝑄ℎ
Determined by simulation
𝑃𝑒
Simulated
𝑄𝑓
𝑃𝑚
13.13/simulated
𝑄𝑚
𝑃𝑜
12.75
𝐼ℎ
€ 1,000,000
𝐶
4% of investment costs
𝐼𝑓
€ 375,000
𝐷
4.5% of investment cost
𝐼𝑚
€ 150,000
𝐺𝐷
€ 71,599
𝐼𝑟𝑓
€ 2,530,000
𝑆ℎ
€ 1.45 per kg
𝐼𝑠
€ 100,000
𝑞1
75%
𝑊
€ 0.34 per MWh
20% < € 200,000 and
25% > € 300,000
6.6% (WACC)
𝑞12
37.5%
𝑞13
60%
𝜏
𝑟
One of the disadvantages of the NPV method is that it does not take the size of a project or the overall
project context in consideration. Therefore in order to compare the NPV of different projects the
present value index can be used (Edmonds, et al., 2009). The present value index is calculated as the
ratio of the present value of inflow to outflows and the higher the ratio the higher the rate of return
per euro invested.
Following the studies on the economics of power-to-gas of Wouters (2014) and Veijer (2014), the real
option valuation (ROV) is applied in this research to optimise the various power-to-gas modalities, the
scale of operations and output options explored. For instance, it may be an attractive option to vary in
operating scales, e.g. depending on electricity prices, or to vary the application of hydrogen and/or
oxygen, depending on their prices (Deng, et al., 2001). In order to assess the feasibility of various
options, a Monte Carlo (MC) simulation technique is applied to simulate electricity price impacts, and
by doing so to evaluate investment projects and to analyse and assess risks. During the simulations
process random scenarios are developed using input variables for the project’s key uncertain variables,
which are selected from appropriate probability distributions.
The Ohrnstein-Uhlenbeck mean‐reversion stochastic process is applied to the MC simulations (this
process is preferred above the basic Geometric Brownian Motion (GBM) since electricity follows a
mean reverting process instead of a GBM process). The mean reverting process of electricity prices can
be tested by performing a unit root test.
The following assumptions of the operational model have been used, and are partially based on
Wouters (2014) and Veijer (2014).

Decision-making assumptions
o The system operator maximises profit each hour depending on the given output quantities
and prevailing prices.
o The system operator is able to predict day ahead output prices.
46
o


The decision-making is not affected by competition; competitors do not influence the
operational strategy.
o The time to build the factory is zero, the facility is relatively small in size and electrolysers,
methaniser and fuel cells are commercially available.
o The location is chosen such that there is an access to wind farms, pipelines and sources of
CO2.
o The operational expenditures are estimated to be 4% of the CAPEX (Greiner, et al., 2007).
Technical assumptions
o Electricity can be bought freely on the market for arbitrage purposes, i.e. no legal
constraints.
o Input electricity can be charged at a continuous basis, there are no load constraints.
o No energy is lost during storage.
o Hydrogen and oxygen can be stored near the plant.
o Plant operations do not influence the market-clearing price.
o Electricity and gas can be sold against public wholesale market prices.
o There are no constraints to selling any of the outputs on a particular day.
o The daily cost of switching between options is zero.
o Transportation costs are zero.
o Maintenance does not interrupt production.
o Breakdowns do not occur.
o The efficiency of the process is stable over the project‘s lifetime.
Financial assumptions
o There are no capital restrictions, i.e. there is no need to raise external capital.
o The equipment has a fixed salvage value decreasing linearly with the economic lifetime.
o The impact of value added tax does not apply.
Data with respect to the Netherlands’ situation
Electricity prices are based on Amsterdam Power Exchange (APX) data from the Thomson Reuters data
stream (Thomson Reuters, 2015). The daily data (weekdays only) cover the period from April 2006 until
April 2014. Electricity prices are influenced by fixed events, such as hourly and seasonal fluctuations,
as well as random events. Data on daily ahead settlement gas prices from April 2006 until April 2014
are obtained from the Title Transfer Facility (TTF) (Gasunie, 2015). Hydrogen price ranges for different
markets are retrieved from Jansen (2015).
As far as electricity price margins are concerned, the profit generated by the sale of power to the
electricity net greatly depends on the quantity and price. The quantity that can be added to the
electricity net is unconstrained with middle and high voltage grids. The price received per MWh is
determined by a fixed price plus an additional bonus that accounts for seasonal and hourly price
differences (for how this bonus has been determined, see Wouters (2014)). One option to try to take
advantage of electricity price fluctuations via arbitrage (e.g. with the help of EC) is to utilise the
discrepancies between off-peak and peak hour prices. The 2006-2014 daily averages of off-peak and
peak prices are shown in Figure 12.
47
Dutch offpeak prices
60
0
0
20
40
€/MWh
200
100
€/MWh
300
400
80
Dutch peak prices
Jan 01, 2006
Jan 01, 2008
Jan 01, 2010
Year
Jan 01, 2012
Jan 01, 2014
Jan 01, 2006
Jan 01, 2008
Jan 01, 2010
Year
Jan 01, 2012
Jan 01, 2014
Figure 12. Daily peak and off-peak electricity prices from April 2006 until April 2014
In order to simulate electricity prices for the upcoming 20 years, the Ohrnstein-Uhlenbeck meanreversion model retrieved from Wouters (2014) has been used. For the results, see Figure 13.
Figure 13. Historical and simulated electricity prices for the Netherlands
The price of the produced synthetic gas is assumed to be similar to natural gas prices. This assumption
is based on the fact that both gases hold similar physical compositions. For the one day ahead
settlement gas price data relevant for the Netherlands’ market, see Figure 14.
20
0
10
€/MWh
30
40
Dutch gas
1/1/2006
1/1/2008
1/1/2010
Year
1/1/2012
1/1/2014
Figure 14. Day-ahead settlement prices
The overall investment costs of electrolysis depend on the techniques used. Grond et al. (2013) provide
an overview of the currently available commercial and pre-commercial electrolyser technologies and
48
costs (see also Table 7). At this moment, the alkaline electrolyser is the only electrolyser that is
commercially available and costs approximately € 1000 per KWh.
Estimates assume an efficiency of the conversion process of between 68% and 82% (Smolinka, et al.,
2011), or slightly lower (Meier, 2014), see also Table 7. For this research, 75% efficiency is assumed as
a base case. For the electrolyser a lifetime of 20 year and a salvage value of 10% is assumed.
Table 7. Overview of electrolysers (Meier, 2014)
Scenario
Efficiency (%)
Cell voltage
Pressure (bar)
Feed-in
Electrode material
PEM
Worst
35%
2
13,8
Fresh water
Base
60%
1,74
21,9
Best
85%
1,48
30
Alkaline
Worst
Base
Best
67,5%
72,5%
77,5%
2,2
1,95
1,7
1
15,5
30
Potassium Lye (KOH)-water solution
Platinun, iridium, ruthernium, Nickel, Copper, Mangan, Wolfram,
rhodium, polymer membrame
ruthenium
The Alkaline electrolyser needs fresh water infeed. Therefore process water or boiler feed quality
water with a maximum of 0.5 ppm Total Dissolved Solids (TDS) is needed (Meier, 2014). If sea water is
used as input, the required desalination can take place through electrical and thermal processes, and
chemical post-treatment.
The investment cost of water desalination plants are high and can only be borne when certain
economies of scales are reached. For large-scale water desalination plants the variable cost for
desalination are expected to lie between USD 0.50 and USD 1.00 per m3. Table 8 provides an overview
of the existing commercial large-scale desalination systems. The investment costs of either of the three
systems lay between USD 900 and USD 2500 per m³ per day. In comparison, Meier (2014) assumes
desalination cost for a 100 MW system and 4,050 production hours yearly of € 1,450 m³/day. Based
on this, most authors assume a cost price of 1 m3 fresh water in the order of € 1 (to illustrate: the
average cost of water in the Netherlands is € 1.18 per m3 including 33% taxes (Prijsinzicht, 2015);
Mathur et al. (2008), however, use an estimate of € 3.15 per m³. The alkaline electrolysis technique
requires the input of approximately 350 litres of water per 1.2 MWh (Etogas, 2015). In case of a 1 MW
electrolyser, the hourly consumption of water amounts to approx. 300 litres. Therefore, with a daily
production of 8 hours a total amount of 2,4 m³ will be required.
Table 8. Energy consumption and water costs of commercial large-scale desalination (Ghaffour, et al., 2012).
Type
MSF
MED
SWRO
Thermal energy
kWh/m3
7.5–12
4–7
Electrical
energy kWh/m3
2.5–4
1.5–2
3–4
Total energy
kWh/m3
10–16
5.5–9
3–4
Investment cost Total water cost
$/m3 /d
US$/m3
1200–2500
0.8–1.5
900–2000
0.7–1.2
900–2500
0.5–1.2
Assuming an input cost of € 3.15 per m³, the total costs related to water consumption would amount
to € 0.945 per MWh or € 7.56 per day. However, these costs would be lower for large-scale desalination
plants. For the pilot case the assumption is made that no investment in water treatment plants is
needed, because fresh water is transported to the platform.
It is assumed that enough CO2 is available at the platform, in case this is needed for methanation. Also,
it is assumed that the amount of synthetic gas produced by the methanation process can immediately
49
be added to the natural gas grid. The output of the electrolysis process needs storage. The size of both
oxygen and hydrogen storage should be sufficient to comprise one day of production. In case of a 1
MW installation that runs for 8 hours per day, and with a hydrogen production of 210 Nm³ per MWh,
the required size of the storage facility is 1680 Nm³ or 151 kg3. In addition, 840 Nm³ or about 1,200 kg
of oxygen needs to be stored daily4. The storage costs of hydrogen are largely determined by the
physical form of hydrogen and the storage technique applied. With respect to hydrogen storage costs,
National Renewable Energy Laboratory (NREL) data of €1,45 per kg for large-scale hydrogen storage
have been used, covering compression, storage, and dispensing costs (Genovese, et al., 2009). The
costs of oxygen storage are much lower than those of hydrogen storage, among others because
hydrogen is highly explosive. Therefore, the assumed costs for oxygen storage are just € 1,000 – 10,000
for 2,000 litres of storage. Given the 20 years production time, the costs for oxygen storage become
negligible. All in all, the daily storage costs of hydrogen and oxygen are assumed to amount to € 219
and € 0.68, respectively.
As far as the avoided decommissioning cost data is concerned, the data provided by Byrd et al (2014)
are informative for the NSA, even if they provide an overview of the decommissioning cost of a typical
4-Pile Drilling/Production Facility located in the US Gulf of Mexico. The results of their study are
depicted in Figure 15, indicating how decommissioning costs depend on water depth.
On the DCS, on average oil and gas platforms are located on a 7-50 m² water depth. Therefore,
following the findings of Byrd et al (2014) the decommissioning cost of a single platforms is about USD
2 million. Assuming a 4% savings rate, this means that a delay of decommissioning activities for a year
will save the company about USD 80,000.
3 The conversion of Nm³ of hydrogen in kg of hydrogen is based on a volumetric density of 0.08988 kg/Nm³.
4 The conversion of Nm³ of oxygen in kg of oxygen is based on a volumetric density of 1.4291 kg/Nm³.
50
Figure 15. Typical 4-pile drilling/production facility complete removal cost in 2012, in the US Gulf of Mexico
(Byrd, et al., 2014, p. 27).
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54

Smart sustainable combinations in the North Sea Area (NSA)

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